Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Africa (Sub-Sahara) Petroceltic International said that the first of up to 24 new development wells planned in Algeria's Ain Tsila gas and condensate field was successful. The AT-10 well, situated about 2 miles from the AT-1 field discovery well, reached a total depth of 6,578 ft. Wireline logs indicated that the expected initial offtake rate would be comparable to the AT-1 and AT-8 wells, both of which test-flowed at more than 30 MMcf/D. Petroceltic is the operator with a 38.25% interest in the production-sharing contract that covers the Ain Tsila output. The remaining interests are held by Sonatrach (43.375%) and Enel (18.375%). Sonangol reported that it has found reserves in the Kwanza Basin of Angola that could total 2.2 billion BOE, including reserves in a block jointly owned with BP. Block 24, operated by BP, holds an estimated 280 million bbl of condensate and 8 Tcf of gas, totaling 1.7 billion BOE, Sonangol said in a statement seen by Reuters.
Africa (Sub-Sahara) Sound Energy identified significant gas shows at the first Tendrara well onshore Morocco. Drilled to a 2665-m measured vertical depth, the well hit a total gross pay interval of 89 m of gas. The full set of well logs are being processed before the startup of rigless mechanical reservoir stimulation operations, which will be followed by a well test. The company is the operator of the well with a 55% working interest.
Troudi, Habib (OMV Tunesien Production GmbH) | Chevalier, Francis (OMV Tunesien Production GmbH) | Alouani, Wael (OMV Tunesien Production GmbH) | Mzoughi, Wala (OMV Tunesien Production GmbH) | Abdelkader, Omri (OMV Tunesien Production GmbH)
In Tunisian Ghadames sag basin, a significant portion of natural gas resources are looked within low permeability Ordovician sandstones deposited immediately below the Early Silurian Tannezuft world-class source rock.
The objective of this study was to develop an integrated approach to better estimate the amount of gas stored in this emerging play via the analysis of four fundamental elements: 1) the thermal maturity of the Silurian ‘hot shales’ source rock, 2) the trapping mechanism and the architecture of Upper Ordovician paleo-valleys, 3) the impact of diagenesis-lithofacies association on petrophysical properties, and 4) the fracture distribution/density and their contribution in the production.
The Early Silurian hot shales constitute the essential ingredient for the development of a pervasive gas accumulation play. The gas generated at the deeper part of the basin has charged the underlying Ordovician low-permeability sandstones mainly through complex faults system inherited from the basement. During hydrocarbon maturation and charging, pore pressure increases at rates that exceed the normal gradients, leading to local over-pressure as seen in several wells drilled down to the Ordovician reservoirs. Lateral migration via regional faults is confirmed by numerous discoveries at the edges of the basin far away from the gas kitchen.
Besides the structural closures accumulations, more complex structural/stratigraphic or purely stratigraphic traps are deemed within the Late Ordovician, and documented for instance by the development of incised paleovalleys filled with multiple fluvio-glacial and marine clastic sediments (i.e Algeria, Libya). The discovery of hydrocarbon pay zones outside of structural closures and the result of the long term tests confirm this hypothesis.
Based on seismic data it is generally very hard to recognize the paleorelief marking the base of the Late Ordovician sequence. Key elements from core studies, regional correlations, isochore maps and sequence stratigraphy have been combined accordingly, leading to a conceptual model within the observed framework. It is then possible to identify the multiple incision surfaces associated with reservoirs of Jeffara and M'Krata Formations.
The reservoir quality is considered as a major risk in deep areas (>4 km). Although, the primary pores space have been occluded by quartz overgrowths and clay cementation or lost by lithostatic compaction. The substantial gas rates observed in several wells drilled in the junction of NE-SW and NS fault trends constitute an evidence of the contribution of open fracture into the flow.
This new insight into this play has been used by OMV to identify in Ghadames basin the area with possible "Tunnel Valley features", analogues to those drilled in Libya Murzuk basin (
There has been recognition in the oil and gas and mineral extractive industries for some time that a set of unified common standard definitions is required that can be applied consistently by international financial, regulatory, and reporting entities. An agreed set of definitions would benefit all stakeholders and provide increased - Consistency - Transparency - Reliability A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) jointly approved the "Petroleum Reserves Definitions." Since then, SPE has been continuously engaged in keeping the definitions updated. The definitions were updated in 2000 and approved by SPE, WPC, and the American Association of Petroleum Geologists (AAPG) as the "Petroleum Resources Classification System and Definitions." These were updated further in 2007 and approved by SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). This culminated in the publication of the current "Petroleum Resources Management System," globally known as PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and has been used by the US Securities and Exchange Commission (SEC) as a guide for their updated rules, "Modernization of Oil and Gas Reporting," published 31 December 2008. SPE recognized that new applications guidelines were required for the PRMS that would supersede the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. The original guidelines document was the starting point for this work, and has been updated significantly with addition of the following new chapters: - Estimation of Petroleum Resources Using Deterministic Procedures (Chap.
Gryaznov, Andrey (Baker Hughes) | Paludan, Johanne (Baker Hughes) | Bizeray, Morgane (Baker Hughes) | El Menshawy, Ali (Baker Hughes) | Balamaga, Julius (Baker Hughes) | Embry, Jean-Michel (Baker Hughes) | Burns, Chris (Baker Hughes) | Fomin, Roman (Gazprom International) | Aleksakhin, Yuriy (Gazprom International)
A major oilfield services provider was requested by a Russian national oil company to conduct a study of a tight, naturally fractured reservoir in Algeria. The goal was to integrate multiple data types (borehole images, wireline acoustic data, 360-degree core photographs) to generate a representative set of 3D static models describing the natural fracture network (with optimistic, basic and pessimistic cases) and then define fracture permeability. The reservoir is a tight Ordovician sandstone with intensive faulting, a complex facies pattern, and limited well data—all presenting significant challenges.
Fracture interpretation was integrated from different sources, including borehole images, cross multipole acoustic data and 360-degree core photographs. The integration of fracture data from so many sources based on different physical principles enabled fracture modelling with much higher confidence, providing an input for further field development.
The workflow for fracture density determination is divided into several stages: from borehole imaging (including definition of open, mixed and closed fracture types) and acoustic data fracture interpretation to 3D fracture density trend creation and calibration. Image interpretation results show good correlation to acoustic log interpretation results using Stoneley reflectivity and azimuthal anisotropy analysis.
Combining acoustic, core and image logs data allowed organization of the wellbores into fracture classes. Fracture classes are zones of probability about the presence of natural fractures. These classes vary from very high probability (where all data types show presence of fractures) to zero probability (where all data types show no fractures or anisotropy).
The 3D model of fracture density reflects a basic concept: the fracture density decreases away from fault cores, and within the fault cores the fracture density is at a maximum. This observation was supported by many field analogues (including some in Algeria).
There were many intervals of intensive natural fracturing that were identified from images and core photographs. These zones might have contributed significantly to fracture permeability. This idea is supported by well test data analysis: the effective permeability from well tests significantly exceeds the matrix (core) permeability but is within the range of fracture permeability as defined by the continuous fracture network (CFN) modelling.
Various data sets were integrated and calibrated to enable precise identification of fracture density distribution, fracture classes, and dip angle and aperture of natural fractures. These data sets provided input for fracture permeability calculations. Fracture density, fracture aperture and fracture dip angle 3D grids were prepared. Special equations, developed for tight, fractured Algerian sandstones, were applied to calculate fracture properties, e.g., fracture permeability.
Through the close interaction of a multi-disciplinary team it was possible to successfully build a consistent 3D CFN model and to perform fracture uncertainty analysis to determine a variety of high-, mid- and low-fractured permeability cases. This model also supported further 1D and 3D geomechanical modelling studies. This CFN model provided a rapid workflow and robust model for further field development planning and new well placement.
Crude oil and natural gas have been major pillars of the modern civilization during the past century. They are among the most valuable depletable global resources. The energy market has witnessed many oil price shocks during the past several decades. Such instabilities have impacted the global oil and gas industry in ways that have included disruption of investment in the infrastructure, slowdown of advancements in technology development, and backwardness on attracting and training creative solution providers. OPEC (Organization of Petroleum Exporting Countries) has been partly blamed for instigating such price instabilities. Recently, and since the latter part of 2014, in the fear that the shale resource developments may affect the market share of the OPEC producers, oil prices have dropped significantly because of OPEC countries, while suffering losses to their own economies, flooded the market with cheap oil. The global oil industry is now facing a similar situation it has faced several times during the last three decades.
Advantages and disadvantages of low oil prices for both net exporters and net importers of crude oil, as well as the global economy, have been extensively discussed in the literature. Based on the available statistics, while in the short terms, OPEC producers may regain their market shares by producing low cost conventional oil and discouraging shale oil and gas developments, in the long runs, this might not be a successful strategy. OPEC countries in few decades will be paying a high price when their conventional resources reach to levels barely satisfying their domestic needs. Furthermore, because of current orchestrated low prices for shale resources they are preventing their own countries from investing in the development of unconventional resources in terms of technology, manpower and pace of development. In this study we examine the potential of source rock development in some OPEC countries and discuss the importance of realizing the real value of crude oil when it gets to pricing a depletable resource and considering the substitution cost.
This paper presents and compares the results of the creation of a titled Free Water Level (FWL) from two different modeling methods and the impact on field production.
Worldwide there are examples of oil and gas fields with tilted FWL's. These can be generated by different mechanisms. This paper focusses on the modelling of a tilted FWL associated to a hydrodynamic system. There are several methods of modeling a tilted FWL, most of them emphasize on how to create a tilted FWL but lack the correctness of pressure distribution. Two modelling methods were investigated and their results were compared. One is a static method in which a tilted FWL surface is assigned and the respective water saturation (Sw) values are calculated in the model. The second approach is a hydrodynamic method based on the hydrodynamic principle that a tilted FWL is generated by lateral pressure variation related to a water flow below the hydrocarbon bearing interval. Both methods can generate a correct tilted FWL surface and the associated water saturation distribution, but the pressure distribution shows a significant difference depending on which method was applied. The hydrodynamic method delivers a correct pressure distribution in both the hydrocarbon and the water zone as it captures the physical principals of the tilted FWL and aquifer and therefore the corresponding pressure data. In the field-model a realistic stronger pressure support can be observed, leading to realistic recovery figures. The static method provides a correct pressure distribution in the hydrocarbon zone but not in the water zone, and delivers a nonrealistic weaker pressure support, leading to lower production figures. The fundamental difference in pressure distribution has a signiciant impact on a field production and therefore project economics.
In conclusion, proper tilted FWL modeling should provide not only a correct FWL surface but also pressure distribution. In cases where a tilted FWL is associated to water flow below the hydrocarbon zone, the hydrodynamic method based on the hydrodynamic principle is recommended.
Vertical wells are drilled in the In Aminas field in Algeria with various types of drill bits, including polycrystalline diamond compact bits (PDC), tungsten carbide insert bits (TCI), and impregnated (impreg) drill bits. The operator tested a new 6-in impregnated bit with novel cutting structure concepts in an attempt to drill the section in one run. The bit was used on rotary BHA, and high speed motor BHA for two runs in the same section. Both runs did well, and the bit maintained the sharp cutting structure till the TD of the section. The 6-in section comprises mulitple layers of hard abrasive sandstone with unconfined compressive strength up to 35 KPSI, loose shale which is relatively soft and ends with metamorphic rock. The new impregnated bit uses diamond segments imbedded in blades comprising diamond-grit matrix material to create a cutting structure with variable wear along the bit face. This particular combination of diamond and matrix improved overall aggressiveness and durability in the shoulder. To drill efficiently, impregs are paired with high-speed motors or turbines.
Tight oil production will change in the coming decades. The last positive results have opened new opportunities as source of renewal production, using unconventional techniques which are used in conventional fields.
The Hassi Messaoud area is located on the central Sahara and is well known as a major oil production in Algeria.
Eroded by the hercynian unconformity on the Hassi Messaoud field, the Ordovician reservoirs (mainly the hamra quartzites) forms a ring around the Hassi Messaoud dome and represent an oil play with a high potential. Recent drilling in the South of Hassi Messaoud dome has discovered significant oil production in the Ordovician Hamra Quartzite and during the last decade, many discoveries have been made in the, East and South flanks of the Hassi Messaoud dome. In many wells, the oil production is related to the fractured reservoir located in the Hamra Quartzites subcrop belt. Mainly these oil fields are Hassi Terfa, Hassi D’Zabat, Hassi Guettar and Hassi Toumiet. Important volumes of oil in place have been proven.
The reservoir qualities of Hamra Quartzites vary because of diagenetics effects. Most of the log data and core samples show that the potentiality of Hamra Quartzites is a modest reservoir due to the effect of cementation
This reservoir is sourced from the Silurian shale which is the main hydrocarbon source rock across the most of the Saharan platform. In the study area the Silurian shale is well developed in the North and the West of the Hassi Messaoud dome.
The 3D seismic surveys acquired in the area with a fold and field parameters allowing a good resolution, were the decisive tool which modified totally our understanding and knowledge about the structural aspect and at less degree the stratigraphic components of the area.
Combined lithologic and stratigraphic traps are the predominant hydrocarbon accumulation for Ordovician reservoirs. Nevertheless the main risk for the petroleum play elements is related to the fractures development.