Eni started production from the Perla giant gas field located in the Gulf of Venezuela, 50 km offshore. Consisting of Mio-Oligocene carbonates with excellent characteristics, the reservoir is approximately 3000 m below sea level and lies at a water depth of 60 m. The best wells are estimated to produce more than 150 MMscf/D of gas each. The development plan includes 21 producing wells and four light offshore platforms linked by a 30-in. Two treatment trains have been installed at the facility, each capable of handling 150 Mscf/D and 300 Mscf/D of natural gas.

High angle S-shaped and high displacement L-shaped well profiles are preferred now-a-days in Balimara field located in the northeast region of India. Main targets are the deep Clastic reservoirs of Oligocene age. Major events reported are while drilling against dipping formations with differential stuck pipe situations with variety of drilling complications in the unstable formations owing to shales in Tipam sandstone and thin sections of coal and shale alteration in oil bearing Barail sandstone formation. The substantial risk of wellbore instability in accessing the reservoirs with lateral variation in pore pressure threatened the commercial success of the project. This paper elaborates how geomechanical information along with BHA design and chemicals was integrated into the decision-making process during well design and drilling operations to avoid wellbore instability issues.

Wellbore stability analysis through Mechanical Earth Model was conducted using estimated state of stress and mechanical properties of the overburden and reservoirs. The model incorporated data from several sources including geophysical logs, leak-off tests, advanced sonic far field profile and drilling records collected from the earlier wells. Examination of the deviated well bore profiles suggested occurrence of ledges due to lower mud weight and improper drilling parameters while drilling alternate layers of sand, shale and coal in Barail formation. Horizontal stress contrast increases in Barail formation supporting the need of higher mud weight with increased well deviation towards specific azimuth.

The integrated geomechanical analysis provided key information: The 9 5/8" casing shoe should be set at shale layer of Tipam Bottom to isolate upper differential sticking prone sandstone layers with Barail Argillaceous sequence. This will help to drill 12.25-inch hole with 9.6 ppg-9.8 ppg only. Shale layers at Tipam bottom require 10.0-10.5 ppg, while Barail shale requires 10.5 ppg-11.0 ppg for vertical well. When the well deviation increases up to 30deg, mud weight requirement rises to 11.2 ppg-11.8 ppg. Based on analysis, the mud weight at the start of 8.5inch section was raised sufficiently to 10.5 ppg to avoid the hole collapse experienced in the earlier lower angle wells. Later, continuous review of torque and drag along with cutting analysis helped to raise mud weight up to 11.0 ppg till well TD. As a result, lower UCS shale and coal layers are drilled with minimal shear failure and improved hole condition. However, changes to the mud system were needed to limit fluid loss and avoid differential sticking across the sandstone. For deviated section, rotary BHA has been used to improve hole trajectory vs. planned with lesser ledges. Downhole hydraulics has been maintained with proper flow rate and rpm to main hole cleaning. The new well engineered with the integrated geomechanics information has been drilled from surface to extended TD while saving 15 rig days.

Petroleum Geologists typically study hydrocarbon bearing reservoirs, understand the geology, and build numerical models to help better produce hydrocarbon. On the other hand, conventional sedimentologists try to simulate the natural process of sedimentation in laboratory through miniature sand box models to better understand such processes. But a proper integration of the laboratory-based techniques in developing subsurface reservoirs models was always lacking in the industry.

Petroleum geologists developed computer based geostatistical techniques based quantitative statistics like variograms, histograms to develop stochastic models of reservoirs which could be used to put a number and range on the geological uncertainty. However, geostatistics deals more with regularly sampled data, describing their spatial variability and directionality. In development oil fields with many wells sampling the reservoir, geostatistics helps us to create a more predictive subsurface reservoir model. However, in the exploratory state of a field with few drilled wells, the data for geostatistical analysis reduces and a robust conceptual geological is needed to build a predictive subsurface geological model where a proper integration of sedimentology and petroleum geology is required.

Different approaches like conceptual block diagrams of depositional models, average sand distribution maps, training images from present day analogs were tried. However, these were less than optimal, deterministic with a long turnaround time for any robust subsurface reservoir model.

A relatively recent addition to the geologist's set of quantitative tools has been Geologic Process Modeling (GPM), also known as Forward Stratigraphic Modeling (FSM) technique. This technique aims to digitally model the natural processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution based on quantitative deterministic physical principles (Cross 1990; Tetzlaff & Priddy 2001; Merriam & Davis 2001). The results show the geometry and composition of the stratigraphic sequence as a consequence of sea-level change, paleogeography, paleoclimate, tectonics and variation in sediment input. In other words, GPM brings the sedimentologists laboratory sandbox model to a petroleum geologist in his computer with the opportunity of unlimited experimentation. GPM technique is based solely on numeric modeling of open-channel flow, currents, waves, and the movement of sediment. The observed stratigraphy is the result of modeling a physical system which can then be further used for refinement in a geological facies model. (Tetzlaff et. al 2014)

In the current study a 3D reservoir model for a field in Western Offshore India was built based on the results of Geological Process Model (GPM) for the thin deltaic reservoir sands as understanding reservoir continuity from seismic data was not possible. With only 4 wells available in the field, traditional geostatistics based reservoir models were inadequate in explaining the reservoir distribution. GPM based techniques helped not only in mapping the reservoir continuity but also opened up new areas for exploration in the area.

Africa (Sub-Sahara) Aminex Petroleum Egypt (APE), a subsidiary of UK-based Aminex, discovered oil at its South Malak-2 (SM2) well on the West Esh el Mellaha-2 concession in Egypt. Tests showed flow rates of approximately 430 B/D of 40 API gravity crude oil. Based on the findings at SM2, a full field development program will be presented to the Egyptian authorities and the joint venture partners before commercial development. APE is the operator of the license with partner Groundstar Resources. BP Egypt has discovered natural gas in the North Damietta Offshore concession in Egypt's East Nile Delta. The Atoll-1 deepwater exploration well reached a depth of 6400 m and intersected approximately 50 m of gas pay in a high-quality Oligocene sandstone reservoir.

Petroleum Geologists have always been a group who looked at rocks, developed and described depositional concepts, mapping structures to discover and develop hydrocarbons for profit. With the advent of new technologies and computing power, geology started to become a lot more quantitative. The first wave of this new revolution was the introduction of geostatistics and the discipline of geomodelling, dealing with quantitative statistics like variograms, histograms, stochastic models which could be used to put a number and range on the geological uncertainty. However, geostatistics which was originally developed in the mining industry in the 1950's deals more with regularly sampled data, describing their spatial variability and directionality. In majority of development fields, with many wells sampling the reservoir, geostatistics helps us to create a feasible proxy for the subsurface reservoirs, when it is backed by a strong conceptual geological foundation. However, as the number of wells decreases, the data for geostatistical analysis reduces and a geomodeller must rely strongly on the conceptual geological knowledge, to build a predictive geological model rather than the noisy picture which over-reliance on blind geostatistics can provide. Until recently, there was no way of quantifying or visualizing depositional concepts in 3D for a geologist save for few block diagrams and average sand distribution maps. However, these were mostly manual, deterministic with a long turnaround time for any alternate concepts.

A relatively recent and still underused addition to the geologist's set of quantitative tools has been geologic process modeling (or GPM, also called stratigraphic forward modeling). This technique aims to model the processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution on the basis of quantitative deterministic physical principles (Cross 1990; Tetzlaff & Priddy 2001; Merriam & Davis 2001). The results show the geometry and composition of the stratigraphic sequence as a consequence of sea-level change, paleogeography, paleoclimate, tectonics and variation in sediment input. In its scope, GPM is similar to detailed sequence stratigraphy. However, the latter has been developed on the basis of observations and inferences, mostly from seismic data, and conceptual models that specify what stratigraphic relationships should be expected under certain conditions (such as sea-level rise and fall, or variations in sediment input). GPM on the other hand, is based solely on numeric modeling of open-channel flow, currents, waves, and the movement of sediment. The observed stratigraphy is the result of modeling a physical system which can then be further used for refinement in a geological facies model. (Tetzlaff et. al 2014)

In the currents study a 3D geological model for the B-9 field, based on the Geological Process Modeling (GPM) has been attempted Owing to the thin pays in deltaic sands, understanding reservoir continuity from seismic data was not possible. With only 4 wells available in the field, traditional geostatistics based facies models were inadequate in explaining the reservoir distribution. Thus, a combination of Stratigraphic Forward Modeling with Multi Point Statistics is used to accurately capture sub-surface facies heterogeneity.

Saka Indonesia's primary objective of drilling an appraisal well offshore North-East Java was to accurately assess productivity of the three main reservoirs discovered by the exploration well drilled in the Pangkah Block. This paper details the integration of advanced formation evaluation procedures and interpretation of image logs with novel formation testing methods, which were used to plan and optimise drill stem tests (DST) conducted across the three reservoirs.

Deployed on wireline, formation evaluation and electrical borehole image logs were acquired in open hole of the exploration well. Nuclear magnetic resonance (NMR) and image logs were processed simultaneously in near real time to facilitate the planning of the subsequent formation pressure testing and fluid sampling program. Using the recently introduced advanced formation testing technology, reservoir deliverability was accurately established, in addition to characterising fluids insitu and obtaining reservoir fluid samples.

Interpreted results of data acquired on wireline from different logging runs were integrated and consequently used to optimise the well testing program across the intercepted heterogeneous and low permeability limestone reservoirs. In addition to determining porosities, free fluid volumes and the range of permeabilities, Drill Stem Test (DST) zones were confidently defined using the free water levels ascertained by constructed vertical pressure profiles. As a result, DST measurements matched the permeability and productivity estimations across the three pay zones.

The integrated approach of formation evaluation, textural analysis and permeability and productivity measurements enabled the evaluation of three complex limestone reservoirs discovered in this field, which included secondary porosities and interconnected vugs. These results were ultimately verified and confirmed by the well tests conducted across the three reservoirs.

The paper will discuss the advancement of recent technology high definition resistivity imager convey with drilling assembly (Logging While Drilling) to quantify fracture geometry and secondary porosity (vuggs) in highly fractured carbonate. Oligo- Miocene carbonate Kujung formation in East Java Basin will be penetrated with high angle well and completed with Inflow Control Device (ICD) to manage water breakthrough from the presence of the fracture. High definition borehole images typically required to quantify the fracture and vuggs and locate the potential water breakthrough.

High definition resistivity images conveyed with electrical cable has been used for decades to quantify fracture geometry and vuggs. However, the well's risk such as potential stuck and mud losses will be high when the well has been depleted and has high deviation well.

Recent development technology of logging while drilling high definition resistivity images has pixel resolution 0.25". The borehole image was acquired through an array of eight buttons that has the pixel sizes to 0.25" for each button. LWD high definition imaging tool has an advantage of scanning 360 deg along the borehole's circumference without any gap along the borehole. The images acquired while drilling then processed with advance processing to quantify fracture geometry and classification of the porosity in the carbonate system for further optimization on inflow control device position and geometry.

Eni reported a large gas and condensate discovery in the deep sequences of the Obiafu-Obrikom fields on the OML61 block onshore the Niger Delta. The Obiafu-41 Deep well reached a TD of 4374 m and encountered 130 m of high-quality hydrocarbon-bearing sands within the deltaic sequence of Oligocene age. The find amounts to 1 Tcf of gas and 60 million bbl of associated condensate in the deep drilled sequences. Eni said the discovery has further potential that will be assessed in the next appraisal campaign. The well will immediately be brought on production and is expected to flow more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said.

Eni reported a large gas and condensate discovery in the deep sequences of the Obiafu-Obrikom fields on the OML61 block onshore the Niger Delta. The Obiafu-41 Deep well reached a TD of 4374 m and encountered 130 m of high-quality hydrocarbon-bearing sands within the deltaic sequence of Oligocene age. The find amounts to 1 Tcf of gas and 60 million bbl of associated condensate in the deep drilled sequences. Eni said the discovery has further potential that will be assessed in the next appraisal campaign. The well will immediately be brought on production and is expected to flow more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said.