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%).
Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. Asia Pacific Sino Gas & Energy Holdings (SGE) flowed gas (coalbed methane) from its first horizontal well in the Linxing production sharing contract (PSC) in China's Shanxi province.
Saleh, Ibrahim Abdul-Salam (University of Technology / Petroleum Technology Department) | Mahdi, Bashar Saadoon (University of Technology / Computer Sciences Department) | Al-Jawad, Mohammed Saleh (University of Technology / Petroleum Technology Department)
Basrah oil fields contain many unresolved drilling problems, some of which are treated with difficulty, inefficiency, and sometimes leading to a more complex problem. These inefficient problems handling procedures lead to a longer Non-Productive Time (NPT). This lack in efficiency often comes from inadequate preparation, or the slow decision making in the detection of the drilling problems. The main objective of this study is to provide the optimum solutions for the drilling problems in Basrah oil fields on smartphones to achieve credible and quick treatments anywhere on the field.
Tracing of the problems, the gathering process of the field data, and the analysis of the field procedures to treat a problem, all of which were difficulties and challenges faced. Field data deficiency was confronted in many stages.
Throughout this paper, strategies of treatment procedures for the problems that could be encountered while drilling in Basra oil fields are discussed such as Dammam formation's losses, Tanuma's shale instability, Mishrif's special treatments so as not to damage the reservoir, and many others. Discussion of every formation that is drilled from the surface to Mishrif formation will be carried out with the explanation of the problems that was faced in offset wells, in addition to the problems that have a possibility to happen in each formation. The treatments for each problem were based on past field experience and standardized procedures. All of the formations, the problems, and the treatments are constructed in an application called Problems Detector 1.0 (PD) that functions on smartphones that obtains a familiar user interface and can be used anywhere on the field. Two advanced programming techniques are used to construct PD using an Object Oriented Programming language (OOP) that is java, they are the classify algorithm and a well secured database used to enhance the application's capabilities to detect problems and secure the wellbeing of the data that are mounted in PD, respectively.
As a result, a full database of the drilling problems in Basrah oil fields has been constructed. All the problems that could be tackled while drilling with the possibility of their occurrence, the causes of these problems, the indications of the problems on the rig, and the treatment of each problem were all parts of the database set in PD.
Smart phones showed very high efficiency and speed in determining the problems and presenting the solution which can be used on field by the drilling engineer and/or the driller, therefore; the presentation of smartphones to the petroleum industry has proven its importance and value.
Mosola, Amanda B. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Braaksma, Kelley S. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Tai, Po C. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Volkmer, John E. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Grabowski, George J. (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Kendall, Jerry (ExxonMobil Exploration Company Div. Exxon Mobil Corporation) | Liu, Chengjie (ExxonMobil Upstream Research Company Div. Exxon Mobil Corporation)
Evaluation of the depositional environments of Upper Cretaceous strata in the Balambo-Garau sub-basin of the Zagros Foldbelt in western Iran into eastern Iraq provides insight into the distribution of reservoir and seal units, as well as potential trapping configurations. Such mapping within the upper sequences of the Cretaceous suggests a larger impact of Proto-Zagros flexure and localized re-activation of deeper seated structural trends in Iraq and Iran. Environment of deposition and unit thicknesses have been mapped and evaluated across western Iran into eastern Iraq using well logs and biostratigraphic data. From the middle Turonian to Santonian, outer-shelf argillaceous limestones overlie proximal to middle- shelf limestones. The deepening of the sub-basin, part of a broader trend of platform carbonates and associated deeper shelf and basinal facies, is concurrent with eustatic sea-level rise, but may also be affected by large-scale Cenomanian-Turonian adjustment. Environmental belts narrow and deposits lap onto highs exposed by localized uplifts as a result of the reactivation of deep-seated structural trends originating in the Permian (or possibly basement?). Outer- to middle-neritic sediments of the Ilam Formation, which onlap local structural highs, are higher quality reservoir facies of Coniacian–Santonian age and, where sealed, may be potential traps.
Deposits of the latest Campanian to Maastrichtian also show deepening of lower-shelf and basinal environments within the study area. Non-deposition and onlap of deeper water carbonate wackestone to marls onto highs in the Dezful embayment may further reflect the localized reactivation of deeper seated structural trends. Siliciclastic sediments of the Tanjero Formation shed from highs to the northeast are associated with paleogeographic reversal of the Proto-Zagros, depositing turbidites within the proximal thrust-front basin. Despite time-equivalent prolific oil-producing reservoir intervals in Iraq, ongoing deepening due to the Proto-Zagros Foreland Thrust results in largely non-reservoir marl facies of the Gurpi Formation acting as a seal to the underlying units. The Tarbur Formation, present in the Fars region, consisting of shallow-water rudist grainstone and packstone suggests a lack of accommodation created in association with the Proto-Zagros subsidence event.
Tectonostratigraphic trends of the Upper Cretaceous of the Zagros region of western Iran and eastern Iraq show the transition of a relatively quiescent ramp increasingly affected by localized effects of the Cenomanian-Turonian adjustment along with the Maastrichtian inception of Proto-Zagros thrusting and elucidates their impact on reservoir, seal and potential trap distribution within proven and unproven hydrocarbon systems in Iraq and Iran.
In recent years the interest in fractured reservoirs has grown. The awareness has increased analysis of the role played by fractures in petroleum reservoir production and recovery. Since most Iraqi reservoirs are fractured carbonate rocks. Much effort was devoted to well modeling of fractured reservoirs and the impacts on production. However, turning that modeling into field development decisions goes through reservoir simulation. Therefore accurate modeling is required for more viable economic decision. Iraqi mature field being used as our case study. The key point for developing the mature field is approving the reservoir model that going to be used for future predictions. This can be achieved via History Matching. The production of this field is mainly from fractures, and it showed unfavorable decline during the production life from 1952. Thus, well modeling is necessary for developing the field, including history matching.
This study employed a three-dimensional three-phase black-oil dual-porosity model by CMG-Builder/IMEX 2010 simulator using an Iraqi fractured, faulted reservoir model. History matching has been carried out to improve the model which was going to be used in the simulation study. Several modifications were required during the history matching, such as adjusting the vertical fracture permeability, the relative permeability, the aquifer properties, setting fault transmissibility, and the matrix and fracture compressibilities.
The results of the History matching showed excellent agreement between the simulation and the historical profile. Furthermore the recent validated data by history matching have been used for the Iraqi reservoir model by running the CMG/IMEX simulator.
When drilling in an arid region through heavily fractured formations, it can be very challenging to manage drilling-fluid losses and at the same time maintain a downhole-pressure gradient that is compatible with the very-low geopressure gradient windows that are typically encountered in those drilling conditions. Nitrogen- enriched drilling muds may provide a good solution to both problems; however, the properties - such as density, rheology, specific-heat capacity, and thermal conductivity - of this type of drilling fluid are highly dependent on temperature and pressure, and in most cases those characteristics cannot be measured in situ, making it difficult to estimate the actual downhole-pressure conditions. The approach described in this paper consists of the reconstruction of the drilling-fluid-mix properties from the characteristics of its components and the incorporation of the resulting pressure- and temperature-dependent constitutive laws into a realtime multiphase- and multicomponent-drilling hydraulic model to estimate the downhole pressures along the drillstring and borehole as a function of the drilling parameters. Because of the uncertainty of some of the characteristics of the components of the drilling fluid as well as their actual proportion in the mix, the modeled values are only valid within a certain accuracy. Stochastic simulations are made during the estimation of the downhole pressures to ascertain the precision of the calculations. As a consequence, by comparing the obtained interval o confidence on the estimations with actual measurements, it is possible to evaluate whether the drilling conditions are normal or deteriorating. The validity and performance of the derived fluid-model extension are tested by use of a real-time data set recorded during the drilling of a well in the Erbril area of the Kurdish region of Iraq, by use of the wellsite information transfer standard markup language drilling-data-exchange protocol. The model results are reviewed and compared with the actual measurements recorded during the drilling operations. The potential sources of limitation, discrepancy, or error between the modeled and observed well and fluid behavior are discussed, along with potential explanations for the observed wellbore physics seen in the recorded-data feed.
We aim to demonstrate the use of high-resolution sedimentological data during the early phase of the exploration cycle. The data reviewed included more than 1300 m of log sections taken North of Erbil. This was combined with field mapping, a microfacies study and the acquisition of routine core analysis data from plugs to provide a more complete analysis. Subsurface data included lithological information from two wells and 2D seismic lines with a total length of 487 Km.
The study focussed on carbonate sequences including potential and known hydrocarbon reservoirs, notably the Qamchuqa-, the Shiranish-, the Khurmala- and the Pila Spi Formations. As a result a refined stratigraphic and depositional framework for the Lower Tertiary and Upper Mesozoic sequences has been established. The Cretaceous sequences analysed herein display a series of distinct lithofacies types ranging from shallow marine to deeper marine environments, which can be attributed to different main depositional complexes. The Paleogene sequences show a high diversity of lithotypes that relate to fluvial, fluvio-marine, mixed siliciclastic - carbonate shelf and inner platform depositional environments.
Outcrop samples from both Tertiary and Cretaceous dolomites inherit the highest porosities thus presumably best reservoir quality in the subsurface. However, the effect of fracturing cannot be assessed in detail from surface data alone.
A 3D facies model has proven useful in displaying the spatial relationship of the well and outcrop data. The display of facies probabilities improves the recognition of cyclicity within homogeneous dolomite sections. Possible extent and connectivity of geobodies could be assessed with the model.
The results have been compared with, and put into a regional context with data from literature and proprietary selected subsurface data. The outcrop data have been incorporated into a workflow that supported other G&G subsurface disciplines during the exploration phase.
This case study involves a well drilled in the Erbil region of Kurdistan, a region characterized by a low water table and challenging geological conditions for drilling. To achieve the key drilling objectives, the drilling mud was made more buoyant by the addition of nitrogen into the mud column.
In order to get a full understanding of the downhole conditions using this mud, the complete drilling process was modelled in real-time. The model was driven using a real-time WITSML data feed. This transient modeling software calculates downhole pressures, temperatures, torque and drag and cuttings density at all depths in the well bore in real-time, including the depths where there are no physical measurements.
The transient model is continuously updated in real-time to reflect the drilling processes undertaken on the rig (e.g. pipe movement, mud pump activity, thermodynamics). Surface system variables including virtual mud pit levels are also calculated in real-time.
The modelled data is then continuously compared to the sparse data points that are being recorded in real-time, allowing both a continuous calibration of the model with the “as drilled” well operation. The calculation of important drilling parameters such as sliding friction, rotational friction, and hydraulic friction is performed in real-time.
The paper will present the key observations upon the matches between the modelled data and the "as drilled" data and summarise the key lessons learned during the well operations and the real-time modelling processes.
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).
The Oudeh Shiranish reservoir in Syria contains 5.1 billion bbls of 12-16 oAPI crude oil. However primary recovery factor is estimated to be only 5 to 7% of the original oil in place. To increase oil recovery, waterflood, VAPEX, microbial treatment and cyclic steam stimulation (CSS) were examined. Eventually, CSS was selected for a pilot test despite the depth of the reservoir, approximately 1600 meters, was deeper than most successful CSS projects in the world.
The CSS pilot was implemented in September 2006 and suspended in November 2009. The project expanded from 2 to 24 wells. Low steam quality at the bottom of the well proved to be the most prominent challenge due to a combination of heat loss in the wellbore and relatively low steam injectivity. Only hot water reached the bottomhole when steam was injected through casing. Injection into tubing improved steam quality. Vacuum insulated tubing (VIT) produced the best, increasing steam quality to between 20 and 40% at a wellhead steam quality of 80% and an injection rate of 200 m3 CWE/day. The high pressure required to inject into the Shiranish reservoir at close to or higher than initial reservoir pressure conditions means that the latent heat of vaporization is low, compared to the typical CSS injection pressure, resulting in a less effective heating process.
In the study, a new thermal simulation model was developed to examine history-matching parameters, match the well and pad performances and optimize operations if the pilot were to be continued. Excellent history matches were achieved. Forecast indicated that Shiranish CSS performance was positive and could increase oil recovery by up to 100% over cold production.