Moreno Ortiz, Jaime Eduardo (Schlumberger) | Klemin, Denis (Schlumberger) | Savelyev, Oleg (Gazprom Neft Middle East B.V.) | Gossuin, Jean (Schlumberger) | Melnikov, Sergey (Gazpromneft STC) | Serebryanskaya, Assel (Gazprom Neft Middle East B.V.) | Liu, Yunlong (Schlumberger) | Gurpinar, Omer (Schlumberger) | Salazar, Melvin (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Use of numerical models to characterize and evaluate reservoir potential is an industry wide practice, with increasingly more development decisions being substantiated by finite difference models. Advances on hardware and software, along with the ability to effectively incorporate accurate process physics, makes simulation a robust tool for field development decisions, particularly on complex operations such as enhanced oil recovery and/or reservoirs with challenging heterogeneity and pore structures. Use of these models does not come without its challenges where data requirements (and use of special characterization both at lab and field level) increase as does the reservoir characterization granularity and thus model sizes. Unsurprisingly the increase of model precision and data requirements amplifies non-uniqueness of the numerical solutions obtained during any field evaluation including field development planning (FDP). Incomplete/inconsistent datasets pose a further challenge to the accuracy (and arguably risk) of the forecasts by introducing further uncertainty on the process characterization. Use of complementary technology such as digital rock, that would enable mitigate impact of such uncertainties in a timely manner -either at field or laboratory level, is thus highly desirable particularly when dealing with enhanced oil recovery. Compounding the non-linearity effect of the EOR agent characterization is the effect of the augmented numerical artifacts (dispersion, dilution, etc) of which complex chemical implementations are prone to, making the upscaling process from laboratory dimensions to field more complex.
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%).
This following case study details the methodology followed and challenges encountered while drilling in the Shakal Block of North Iraq. A narrow drilling window and geologically-associated problems in the first well, Shakal-1, were enough to demonstrate that non-conventional drilling techniques are needed to develop Shakal field potential. In case of Shakal-2 and Shakal-3 exploration wells, the 12-¼" and 8-½" hole sections applied Managed Pressure Drilling (MPD) technique and Microflux® control system technology to reach planned objectives and reduced a combined 15 days of drilling time, equating to associated cost savings of US$1.8MM.
The primary objective of drilling with these techniques in the Shakal field was to maintain the Equivalent Circulating Density (ECD) within the operative window and keep the downhole circulating pressure close to formation pore pressure in order to minimize nonproductive time, optimize drilling performance and minimize formation impairment.
In addition to the drilling objectives, MPD help was needed in order to safely facilitate trips to surface derived from normal scheduled operations as well as unprogrammed operations caused by tool failures or drilling problems; in some fields like Shakal, pulling out of hole can be equal or more difficult than the actual drilling operation.
All planned operating windows have some degree of uncertainty. In the cases of Shakal-2 and Shakal-3, Microflux control system technology detected early signs of influx and fluid loss when there was a deviation from the anticipated drilling window.
The flexibility of MPD technique during trips with Stripping Method showed high benefits on these holes sections along with accurate monitoring of well parameters for early detection of influx and losses.
The use of MPD contributed to significant time, cost savings and safety increment for the Shakal-2 and Shakal-3 in the 12-¼" & 8-½" hole sections.
The youngest major reservoirs and seals of the northern Arabian Plate occur in the Chattian, Aquitanian, and Burdigalian. They unconformably overlie major reservoirs of the Oligocene Kirkuk Group, shelfal carbonates formed on the northeast margin of the Mesopotamian Basin.
Deep-marine carbonates of the upper-Chattian Ch3 and lower-Aquitanian Aq1 sequences (Serikagni Formation) were deposited within the basin. A thin anhydrite occurs at the base. These pass upwards into shelfal carbonates (Euphrates and Middle Asmari formations), which lie unconformably above older shelfal carbonates around the basin. The basin is completely filled by evaporites and carbonates of the upper-Aquitanian Aq2 sequence and lowstand of the basal-Burdigalian Bur1 sequence (Dhiban Formation and Kalhur Anhydrite). The top of the shelfal carbonates is a subaerial unconformity.
Shelfal carbonates (Jeribe and Upper Asmari formations) were deposited in the transgressive to highstand systems tracts of the Bur1 and Bur2 sequences. Subaerial-exposure surfaces are recognized at the top of each of these sequences. Cyclical marginal-marine to nonmarine evaporites, carbonates and siliciclastics (Transition Beds of the Fat'ha Formation, and lower Gachsaran Formation) lap onto the underlying sequences. In parts of northern Iraq the Basal Fars Conglomerate occurs at the base of the Fat'ha Formation, composed of pebbles of the underlying Oligocene-Miocene carbonates and various lithoclasts of Jurassic-Paleogene age transported from the hinterland to the northeast. Deposition of the evaporite-bearing Fat'ha Formation ended in the late Burdigalian to early Langhian.
Oolitic-skeletal grainstones and skeletal-peloidal packstones and wackestones of the Euphrates and Jeribe formations are partly to completely dolomitized and have 8-20% interparticle, intercrystalline and moldic porosity and 1-10 mD permeability. Basinal wackestones and mudstones of the Dhiban and Serikagni formations are dolomitic and have 10-17% porosity with <1 mD permeability. Thin limestones of the Transition Beds have 4-15% porosity with <1 mD permeability. Evaporites of the Fat'ha and Dhiban formations are the primary seals for these reservoirs.
Stratigraphy and Age Framework
The lithostratigraphic units of Iraq and Iran and the ages of the Lower Miocene formations from the northern Arabian Plate are shown in Figure 1. Major sequence boundaries occur at the top of the Transition Beds of the Fat'ha Formation and the Jeribe and Euphrates/Serikagni formations. The basin-filling evaporites of the Saliferous Beds of the Fat'ha Formation and the Dhiban Formation are lowstand-transgressive deposits formed during one and a half sequences.
Carbonates of the lower Aquitanian and lower and middle Burdigalian are porous and form reservoirs for oil and gas. Evaporites of the upper Aquitanian and upper Burdigalian form seals for these reservoirs.
Biostratigraphic control is lacking or imprecise for these marginal- to shallow-marine carbonates and evaporites. We have relied extensively on strontium stable isotopes of anhydrite for age constraints. The 86Sr/87Sr ratio increases steadily from 0.7083 at the base of the Aquitanian to 0.7089 at the top Langhian. The results are summarized in Figure 2.
Tai, Po C. (ExxonMobil Exploration Company) | Grabowski, George J. (ExxonMobil Exploration Company) | Liu, Chengjie (ExxonMobil Exploration Company) | Kendall, Jerry (ExxonMobil Exploration Company) | Wilson, Augustus O. (Consulting Geologist)
The Sinjar Trough is a major east-west trending extensional feature in Northwest Iraq and Northeast Syria. It began to develop in the Late Cretaceous (the Maastrichtian) due to transtensional tectonics and was inverted during the late Pliocene-Pleistocene as a result of the Zagros Orogeny. Through biostratigraphic, Sr-isotope age dating, petrographic, and sequence-stratigraphic studies of two late Oligocene-earliest Miocene basin-center evaporite intervals in Northwest Iraq and adjacent Northeast Syria, we recognized several minor episodes of inversion in the Sinjar Trough during the Paleogene.
The Basal Serikagni Anhydrite (BSA) is a thin basinal anhydrite unit imbedded between the middle and late Chattian deep-marine carbonate sequences. The BSA extends into Northeast Syria but is missing in several adjacent wells within the Sinjar Trough.
The Dhiban Formation is a thicker late Aquitanian-early Burdigalian evaporite-dominated interval mixed with carbonates. It overlies the Serikagni Formation and onlaps onto the carbonate ramp margins of the Euphrates Formation, which prograded towards basin center from the northeast and southwest. In Northeast Syria, the same basin-center evaporite is called the Dibbane Formation and shows local thickening and thinning. The overlying Jeribe Formation, however, has a uniform thickness across Iraq and Northeast Syria.
The areal distribution, facies, and stratal geometry of these basin-center evaporite-bearing intervals reflect the antecedent topography during their deposition. Minor inversions within the Sinjar Trough before or during the late Oligocene caused non-deposition or erosion of the BSA in Northeast Syria. Another episode of inversion before the early Miocene created low-relief highs and differential accommodation within the Sinjar Trough. The Dhiban/Dibbane Formation simply filled the remnant basin and was able to cover the highs during the lowstand stage, resulting in local variations of the basin-center evaporite accumulation. This study may shed some light on the timing of early trap formation within the Sinjar Trough.
Tectonic Setting, Tectonic History, and Hydrocarbon System of the Sinjar Trough
The Sinjar Trough is an east-west trending Late Paleozoic-Mesozoic rift basin (~250 km long, 50 km wide) that is located in Northwest Iraq and Northeast Syria (Best et al., 1993; Brew et al, 1999; Figure 1). It is a possible eastern extension of the Palmyride rift system but has less intense Paleozoic history of extension, thermal subsidence, and sediment accumulation (Best et al., 1993). The major extension took place during Late Campanian-Maastrichtian time and the east-west striking faults formed the Abd el Aziz and Sinjar grabens, in which thick Maastrichtian Shiranish Formation (up to 5000 ft) was deposited (Brew et al., 1999, 2001). Normal faulting ceased abruptly by the end of the Cretaceous, and the Paleogene was mostly a time of tectonic quiescence (Brew et al., 1999). Full-scale inversion by reactivation of east-west striking normal faults formed fault propagation folds during late Plio-Pleistocene time and inverted the grabens as surface anticlines (Kent and Hickman, 1997; Brew et al., 1999, 2001). Deformation increases to the east in the Iraqi Sinjar region (Brew et al, 2001).