A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.

The Jurassic–Cretaceous petroleum system of southern Iraq contains excellent source, reservoir, and seal rocks leading to the presence of several giant oil fields (Figure 1). According to detailed organic geochemical characterization, the oil, which is mainly trapped in Lower Cretaceous sandstone and carbonate reservoirs, was generated from organic matter-rich Upper Jurassic to Lower Cretaceous carbonate source rocks (Abeed et al., 2012). Evaporites and compacted mudstones seal the reservoir rocks effectively (Figure 2). Whereas new investigations have documented the maturation of the source rocks and the characteristics of the oils reservoired in this area (Pitman et al., 2004; Al-Ameri et al., 2009; Abeed et al., 2011, 2012), a detailed basin-modelling study, specifically for this area, has not yet been published. This paper is based on a 3-D basin model, focusing on the structural aspects as well as the generation, migration and accumulation of hydrocarbons within the Mesozoic sequences in the Basra region, southern Iraq.

Several 1-D burial-history models have been constructed for individual wells (Figure 1), of which one for well R-172 is discussed in this study. Rumaila Well R-172 is a deep well that penetrates the Jurassic Gotnia evaporites (Figure 2). A 2-D model for the studied sequence was extracted from the 3-D model. It reveals the general geometry of the hydrocarbon structural traps. The 3-D model has been built based on the interpretation of 12 seismic sections across the study area. The data for this model are derived from general geological information on sedimentology and tectonic evolution of the area, along with several well reports as well as organic geochemical data on source rock core samples and crude oils published in Abeed et al. (2011, 2012). In order to provide the constructed model with the required data on petroleum generation characteristics, three source rock samples have been analysed for kinetic parameters.

Only a few detailed scientific studies on the Mesozoic petroleum system of the Basra region have been published so far. A preliminary attempt to investigate the geothermal gradient of southern Iraq was written by Ibrahim (1984). Pitman et al. (2004) studied petroleum generation and migration in the Mesopotamian Basin and the Zagros Fold Belt of Iraq by applying basin modelling software. The petroleum system of a single reservoir rock (Mishrif) in three different oil fields in Basra has been studied by Al-Ameri et al. (2009). Studying an entire petroleum system within a basin requires a detailed understanding of the geological history of source, reservoir and seal rocks, as well as an analysis of the varying geological processes that affected the basin through geological time, such as erosion, uplift, or the evolution of salt diapirs. Moreover, migration pathways and traps need to be interpreted correctly to achieve a model of petroleum accumulation.

The most likely source rocks for the Cretaceous hydrocarbons in the Basra region, southern Iraq, are the Upper Jurassic to Lower Cretaceous Yamama and Sulaiy formations (Al-Ameri et al., 2009; Abeed et al., 2011, 2012). The Upper Jurassic to Lower Cretaceous successions are marine carbonates with a very good hydrocarbon generation potential, which were deposited under anoxic conditions. Thickness of the succession exceeds 600 m in southern Iraq (Sadooni, 1993; Jassim and Goff, 2006). The Yamama Formation in southern Iraq was examined in wells Su-8 (Subba) and R-172 (Rumaila) and shows a predominant input of marine organic matter and a good source rock potential, both in terms of quantity and quality of organic matter (Abeed et al., 2011). The underlying Sulaiy Formation represents a similar organic facies, as indicated by carbonate content and organic matter quantity, but is much more mature; therefore, most of the petroleum generation potential has already occurred.

Biomarker data are scarce for the Sulaiy Formation due to this high maturity. Therefore, biomarker data of the Yamama source rock were compared to those of crude oils from the Zubair reservoir, showing a good oil-source rock correlation (Abeed et al., 2012). The sediments in both the Sulaiy and Yamama formations were accumulated in a predominantly dysoxic-anoxic environment (Al-Ameri et al., 1999). The Sulaiy Formation can be regarded as an excellent source rock, which has already realized most of its petroleum generation potential. Maturity parameters suggest that this formation has reached and passed peak oil generation, but has not reached the dry gas generation zone (Abeed et al., 2011).

Cretaceous carbonate and clastic rocks are the main reservoirs in southern Iraq, with the Mishrif, Nahr Umr, and Zubair reservoirs being the economically most important ones (Beydoun, 1986). In addition, Abeed et al. (2012) have demonstrated the importance of the Yamama reservoir, which contains the lightest oil of the Basra oil fields. The porosity exceeds 20% in the carbonate reservoirs and reaches values greater than 30% in the clastic reservoirs. Permeability varies from low permeability in the Ratawi reservoir (e.g. Tuba oilfield) to greater than 1,000 milliDarcy in the Zubair, Shu’aiba, and Nahr Umr reservoirs (Jassim and Goff, 2006).

The Upper Jurassic Najmah limestone is the primary Jurassic reservoir. This unit consists of oolitic limestones, dolomites, and anhydrites that were deposited in a shallow-marine and transitional marine setting composed of lagoons and shoals, similar to the Arabian and southern Arabian Gulf Basin (Fox and Ahlbrandt, 2002).

The Gotnia Formation is a regional seal in Iraq. It was deposited on the very shallow southern platform in a sabkha environment (Lurestan Basin), as basinal salt and laminated anhydrite and shales (Murris, 1980). It is about 200 m thick and forms a tight seal for local oil and gas accumulations in the underlying Najmah Limestone (Fox and Ahlbrandt, 2002).

During Cretaceous times, several shales were deposited, which act as seal rocks. Only some of the compacted shales formed efficient seals, e.g. no producible oil was encountered in the Mauddud Formation in southern Iraq, although it is an important reservoir in the Middle East. This is either due to the inefficiency of the Ahmadi shale as a cap rock in southern Iraq or due to the presence of shale beds in the upper part of the Nahr Umr, which generally act as cap rocks in southern Iraq and which may prevent vertical charging of overlying reservoirs (Ibrahim, 1983; see Figure 2).

All wells in the central, eastern, and southeastern parts of southern Iraq were drilled on structural prospects (Ibrahim, 1983). The most abundant traps of southern Iraq are elongated narrow anticlines. These structures are mainly NS-trending, possibly originating from the Neoproterozoic Nabitah orogeny. They were reactivated during the Carboniferous–Permian, Mesozoic and Tertiary (Jassim and Goff, 2006). The structures in the Mesopotamian Zone usually have positive residual gravity anomalies. However, the well-defined anticline oil fields of Zubair, Rumaila, and Nahr Umr in the Zubair Subzone in the south are associated with negative residual gravity anomalies. This might suggest that salt is present below the Cretaceous units in some of the structures in southern Iraq (for more discussion see Jassim and Goff, 2006).

The southern Mesopotamian Basin in Iraq (Zubair Subzone) holds one of the largest petroleum accumulations of the world. The Cretaceous Zubair and Mishrif reservoirs contain about 60% of Iraq’s known hydrocarbon reserves (Aqrawi et al., 2010). The oils from Lower Cretaceous reservoirs are non-biodegraded, have a high sulfur content and an API gravity in the range of heavy to light oil (19–40° API). They were generated and expelled from a marine carbonate source rock bearing a Type II-S kerogen signature with the most heavy oils being related to an early petroleum generation and expulsion stage (Abeed et al., 2012). The area of southern Iraq oil fields is also very rich in associated gas and condensates.

Seismic Interpretation and Well Control

For seismic interpretation we used 12 regional seismic lines of 8 to 8.5 seconds two-way time (TWT), with three lines trending N-S and nine lines trending E-W to ENE-WSW. In addition 14 wells with total depths ranging between ca. 3,000 and 5,700 m were included in the study. The stratigraphic tops are based on well reports and assumed to be true vertical depth. Most of these wells are located on the anticlines of subsurface structures and along seismic profiles. However, some wells are located distant to the available seismic data at the outer limits of the study area.

The seismic horizon interpretation was carried out using Petrel software (Schlumberger) by combined manual and automated reflector tracking. Initial horizon input for the Gotnia, Najmah, Butma, Mishrif, Zubair, Yamama and Sulaiy reflections was provided by the Oil Exploration Company in Baghdad (OEC), along profile “rr14e” (Figure 3). The seismic interpretations were then extended to the other profiles. Interpretation towards unconnected profiles was carried out using extrapolation surfaces of existing interpretations combined with TWT depth estimates of stratigraphic layers, the identification of prominent reflections and roughly time-converted well top interpolation surfaces. The resulting area-wide horizons were then depth-converted using a grid of regularly spaced interval velocities, provided from seismic data, and adjusted to existing well tops. Finally, area-wide horizon interpolation surfaces with a 250 × 250 metre grid spacing were created, incorporating the depth-converted interpretations and well tops.

Based on the locations of seismic profiles and well tops, the density of data input to the interpolation surfaces strongly differs. The highest data density is found in the central to the northwestern and eastern study area, while towards large areas in the southern and in some parts of the northern study area mainly interpolation was used, leading to higher uncertainty of the subsurface structure.

Petroleum System Modelling

Petroleum system modelling refers to numerical computer models that incorporate geoscience data and can be used to analyse the formation and evolution of sedimentary basins. Usually a finite-element forward-modelling approach is adopted to simulate the burial history of sediments, including compaction, pressure and temperature, as well as the maturation of organic matter, petroleum generation, migration and accumulation through time. Principles of basin modelling have been described by Welte and Yalcin (1988) and Hantschel and Kauerauf (2009). We generated the 3-D model using the PetroMod software of Schlumberger. The modelling requires input data that describe the present-day geological configuration, and the geological history is simulated from the oldest event to the most recent one. Initially, the model was based on seismic interpretation.

For chronostratigraphic subdivisions the time scale of the Lexique Stratigraphique International (van Bellen et al., 1959-2005) and International Commission on Stratigraphy (2008) was used. The input data include thickness, lithology, heat flow and absolute ages for each stratigraphic unit and each event. The 3-D model includes 26 layers from the base of the Lower Jurassic Butma Formation to the Pliocene Dibdibba Formation and is based on the UTM Zone 38 (Northern Hemisphere) coordinate system using the WGS 84 datum. Depositional ages and related lithologies are shown in Table 1.

The stratigraphic information and the thickness values for the Fatha, Dammam, Rus, Tayarat, Mishrif, Zubair, Yamama, Sulaiy, Gotnia, Najmah, and Sargelu formations are based on the seismic interpretation (Figure 4). Additionally, the model contains thickness maps of the Ghar, Umm Er Radhuma, Shiranish, Hartha, Saadi, Tanuma, Khasib, Rumaila, Ahmadi, Mauddud, Nahr Umr, Shu’aiba and Ratawi formations, which are based on a uniform splitting process in Petromod (splitting ratio; see Table 1). The subdivision was needed because of the interlayering of the Petroleum System Elements (PSE) and the occurrence of several source rocks within the whole system. At the base of the model, a basement layer (Butma) was assigned with a uniform thickness of 1,000 m. Lithological information has been derived from different well reports as well as from published literature (e.g. van Bellen et al., 1959-2005; Al-Sharhan and Nairn, 1997; Jassim and Goff, 2006; Aqrawi et al., 2010). For each layer, a user-defined lithology was created in PetroMod software. The petrophysical properties of the lithologies applied are summarized in Table 1.


Several source rocks were identified in the Mesopotamian Basin and characterized by organic geochemical methods (Abeed et al., 2011). Due to the high maturity of the Sulaiy Formation, we selected source rocks from the Yamama and Zubair formations for kinetic analysis. The Yamama and Sulaiy formations represent similar organic facies whereas the Zubair Formation is more terrestrial influenced, having a lower petroleum generation potential and lower maturity within the basin. Due to the greater terrestrial influence it may be regarded as gas-prone rather than oil prone.

Bulk kinetic parameters were determined at GFZ Potsdam (German Research Centre for Geosciences) for three samples. The samples (Zubair 1 and 2, both Barremian; Yamama, Berriasian–Valanginian) were analysed by way of non-isothermal open system pyrolysis at four different heating rates (0.7, 2.0, 5.0 and 15°C/min) using a Source Rock Analyzer© (Humble Instruments & Services, Inc.). The generated bulk petroleum formation curves served as input for the bulk kinetic model, consisting of an activation energy distribution and a single pre-exponential factor. The pyrolysis products are transferred by a constant helium flow (50 ml/min) and detected by a Flame Ionization Detector (FID). Low heating rates were used to avoid heat transfer problems that might influence the product evolution curves, and consequently the geological predictions (Schenk and Dieckmann, 2004). The discrete activation energy distribution with a single frequency factor was determined using the Kinetics 2000 software (Burnham et al., 1987).

For petroleum system modelling, we defined the Yamama and Sulaiy as source rocks, using a TOC value of 5.0% and 1.5% and an initial HI value of 600 and 500 mgHC/gTOC for the Yamama and Sulaiy, respectively. To calculate the petroleum generation, we used the bulk kinetic information from the Yamama Formation. More source rock data are discussed in Abeed et al. (2011).

Bulk Kinetics

Measured pyrolysis product-generationrate curves were used to calculate the kinetic parameter datasets for selected samples from the Mesopotamian Basin. These comprise discrete activation energy distributions for first-order reactions with an Arrhenius-type temperature dependence, using a single pre-exponential (frequency) factor. The activation energy distributions and the corresponding generation rate curves for all three samples are listed in Table 2. The Barremian Zubair samples were carefully selected from immature organicrich black shales. Both are characterized by a slightly narrower activation energy distribution indicating a more homogeneous organic matter assemblage. Using the bulk kinetic parameters, the evolution of vitrinite reflectance, generation rates and transformation ratios (temperature and timing of petroleum generation) were calculated for a geological heating rate of 3°C per million years. This heating rate corresponds to an average geological heating rate in sedimentary basins (Schenk et al., 1997). The results in terms of temperature versus generation rate with calculated vitrinite reflectance curves for the Zubair and Yamama samples are presented in Figure 5. Under the conditions mentioned above, significant petroleum generation from Zubair samples starts between 100° and 110°C, with peak oil generation at 140°C. The initial oil generation from the Yamama begins at lower temperatures, i.e. 70–80°C, indicating kerogen Type II-S, which is also confirmed by the results published in Abeed et al. (2012). The peak oil generation of Yamama is close to 140°C.

Seismic Interpretation

The seismic data show very smooth, continuous and parallel to slightly sub-parallel reflections of the sedimentary succession. They image several gentle-dipping, approximately NS-trending fold structures with fold amplitudes of up to 500 m and a mean fold frequency of 20–25 km. The fold amplitudes clearly increase with depth, while the uppermost sediments are less deformed. However, sections cutting more-or-less perpendicular to the fold axes image the folds from top to base of the profiles. The folds include three prominent, NS-trending anticlines with N-S to NW-trending synclines in between. The higher density of data in the central study area provides clear evidence for the occurrence and geometry of the folds while the lack of data, especially concerning E-W cross sections towards the south does not allow for clear identification and detailed interpretation of the structures across the entire study area. A large-scale anticline in the SW study area is based on surface interpolation towards a single well and remains of high uncertainty.

Further, seismic data reveals only a limited occurrence of faults. Single faults or fault sets with small offsets are observed only in the deeper core parts of anticlines at stratigraphic levels below the Gotnia Formation. Based on the low density of data and the small size of faults, only one antithetic fault set could be traced within the central anticline across at least two seismic cross sections and indicates a fault trend almost parallel to the fold axes.

Source Rocks Maturity and Hydrocarbon Generation Potential

The stratigraphy in the Mesopotamian Basin is divided by four unconformities (Albian/Aptian, Cenomanian/Turonian, Maastrichtian/Paleocene and Eocene/Miocene age), which can be either erosional or non-depositional phases. Pitman et al. (2004) concluded that the amount of Cenozoic strata eroded in the study area was low (less than 500 m). Also the total erosional thickness of Cretaceous units is quite low (not more than 300 m in total), so that it has little impact on the modelling results with respect to present day maturity, petroleum generation and accumulation. Therefore, erosion was not taken into account for 3-D modelling. However, we assigned short phases of non-sedimentation related to the ages of unconformities (see Table 1).

The thermal history of the sediments and the evaluation of source-rock maturation and petroleum generation are based on the heat flow history, which had to be defined through the geological evolution. Deepest burial and maximum maturity in the study area is reached at present day. Thus, the palaeo-heat flow is difficult to assess. Present-day temperatures (corrected BHT) and measured vitrinite reflectance data of several wells were used for calibration. Reflectance values are generally low and therefore, we used a constant heat flow of 50 mWm–2, which is lower than the global average values for continental crust. Pitman et al. (2004) used an even lower heat flow estimate of 45 mWm–2 for the Mesopotamian Basin. This even lower heat flow also still fits to the observed vitrinite reflectance data. This is visible in the vitrinite reflectance-depth plot shown in Figure 6: the calculated vitrinite reflectance is slightly higher than the measured values indicating a lower heat flow during maximum burial, i.e. at Neogene times.

However, it is noteworthy to mention that we had to increase the present-day heat flow to 60 mWm-2 in the 3-D model in order to achieve a fit with the high present-day borehole temperature. In other words, there is a small misfit between measured present-day temperatures and measured vitrinite reflectance values. One possible reason for that is that measured vitrinite reflectance values are “too low”, e.g. by “bitumen impregnation” of vitrinite or by the presence of special, hydrogen-rich vitrinite-precursors (“perhydrous vitrinite”; see Taylor et al., 1998). However, other geochemical maturity parameters confirm measured vitrinite reflectance (Abeed et al., 2011). Other explanations include wrong corrections of measured bottom-hole temperature or a change of the geodynamic regime towards higher heat flow during the Neogene. We applied this last possibility here but cannot exclude the other ones.

The Late Neogene temperature is the maximum burial temperature of the sedimentary succession in the southern Mesopotamian Basin. This is clearly evident from the results of temperature logs and vitrinite reflectance profiles. Assuming the present-day borehole temperatures and the Neogene burial history is sufficient to reach the measured vitrinite reflectance data, i.e. it is not necessary to assume any deep burial/erosion or high heat flow events (Petmecky et al., 1999) in the geological past. Further evidence is derived from the subsidence history, revealing no periods of rapid sedimentation related to crustal thinning and rifting, which would necessitate an assumption of high palaeo-heat flows (Baur et al., 2010). Accordingly, an assumption of a simple constant heat flow over time is justified instead of a complex pattern of heat flow evolution (Beha et al., 2008). This rather simple subsidence pattern is also a consequence of the absence of major tectonic activities (Pitman et al., 2004). The relative tectonic stability of the Mesopotamian Basin that prevailed after hydrocarbon trapping could be one of the important reasons that led to the preservation of huge hydrocarbon accumulations, as this relative stability is responsible for the absence of major faults, which could lead to seal failure and dismigration.

A 1-D burial and temperature diagram for the deep Rumaila Well R-172 is shown in Figure 6. The formations that overlay Yamama are immature, whereas the Upper Jurassic–Lower Cretaceous sediments are within the oil window. They are now situated at a maximum depth of about 4,000 m and have reached the maximum source rock temperature of about 120–130°C. In Well R-172 (Figure 6) the Sargelu Formation reached a maximum temperature of about 140–150°C and a depth of 4,550 m. Calibration of this 1-D model was performed using measured vitrinite reflectance data from the Zubair, Ratawi, Yamama, and Sulaiy formations published in Abeed et al. (2011). In addition, the model was also calibrated using present-day temperatures for the wells. They were extracted from unpublished INOC schematic maps (March 1979) of temperature distributions at depths of 1,000, 2,000 and 3,000 m in Iraq.

The Transformation Ratio (TR) and maturity of the source rocks were modelled for Well R-172. There is a clear contrast between the modelled TRs using the published kinetic data set for Type II-S kerogen of Lewan and Ruble (2002), which is implemented in the PetroMod software, and our source rock specific kinetics. According to the kinetics of Lewan and Ruble (2002), oil generation from both the Sulaiy and Yamama source rocks commenced during the Early Cretaceous at about 132 and 126 Ma, respectively. Complete conversion to petroleum (TR = 1.0) was already reached in the Late Cretaceous at about 102 and 95 Ma for the Sulaiy and Yamama source rocks, respectively (Figure 7). However, based on our own kinetics, hydrocarbon generation commenced much later, in the Late Cretaceous, at 97 and 93 Ma for the two source rocks, when the vitrinite reflectance (VRr) reached 0.65%. Furthermore, TRs based on our kinetics reached only 0.5 and 0.4 for Sulaiy and Yamama source rocks, respectively, at present time (Figure 7). The difference in the kinetic calculations might be partly due to the fact that the Yamama source rock used for our kinetic data study was not immature, but has already reached the early mature stage of petroleum generation. Therefore, some of the petroleum might have been generated already and generation of this “early” petroleum cannot be reproduced in laboratory experiments. Since the large quantities of hydrocarbons accumulated in the reservoirs of the southern Mesopotamian Basin are mainly or exclusively derived from the Upper Jurassic–Lower Cretaceous source rocks and since much of this oil has low API and high sulphur contents (Abeed et al., 2012), we tend to believe that the kinetics of Lewan and Ruble (2002) provides results closer to reality.

Figure 8 shows a 2-D cross section trending E-W across the study area. The cross section has been extracted from the 3-D model and shows several anticline structures that act as hydrocarbon traps. Generally, anticlines and synclines are wide (with occasional narrower features) and the general geometry of these structures suggests an origin from a gentle tectonic compression. No strong effect of salt diapirsm can be seen in the seismics. Figure 8 also shows the maturity zones using the EASY %Ro algorithm of Sweeney and Burnham (1990).

Results of the 3-D model concerning the temperature distribution of the source rocks in the Late Cretaceous (65 Ma) and at present-day are shown in Figure 9. In the Late Cretaceous the Yamama layer reached a maximum temperature of about 115–120°C (Figure 9a) in the western part and also east of Well R-167. The Yamama layer remained at lower temperatures of about 100°C in the north, between wells West Qurna WQ-114 and Rumaila R-172, and also in the east. This indicates that oil generation in this source rock commenced before the Late Cretaceous (earlier than 65 Ma), especially in the “hotter” and deeper parts of the basin. At present-day the temperature of the Yamama source rock in Well R-167 is 140–150°C in the area close to this well and east of it. The lowest temperatures occur in the north, between wells WQ-114 and R-172 with temperatures of about 120–130°C (Figure 9b), and also in the east. The general pattern for the Sulaiy source rock is very similar to that of the Yamama, but temperatures are shifted to higher values, usually by 5–10°C. In the Late Cretaceous this formation reached a maximum temperature of about 125°C at different spots in the central and southern part of the study area. At present-day the highest temperatures are found for the Sulaiy source rock to the north and the east of the Well R-167.

Based on the EASY %Ro equation of Sweeney and Burnham (1990), the Yamama source rock reached the main oil generation stage (0.7–1.0% VRr; peak oil generation) only in the western part of the study area, while only the early oil stage (0.55–0.70% VRr) was reached in the east and north (Figure 10a). At present-day (Figure 10b), all layers are in the main oil generation stage, except for the two locations to the north and east of Well R-167, which reached the late oil stage (1.0–1.3% VRr). In the Late Cretaceous the Sulaiy source rock was within the main oil-generation stage, except for two regions around Well WQ-114 and to the northwest of Well R-172 (Figure 10c), where maturity was lower. Currently, Sulaiy source rock partly occurs within the late oil generation stage (Figure 10d).

Figure 11 shows the transformation ratios (TR) of the source rocks based on the kinetics for the Yamama source rock discussed above. In the Late Cretaceous, about 40% of the Yamama kerogen was transformed into hydrocarbons in most of the western part of the study area according to our model and much less in the north and east (Figure 11a). At present, up to 72% of the kerogen has been transferred to hydrocarbons north and east of Well R-167 and much less in the northern and easternmost areas (Figure 11b). The general pattern of TRs is similar for the older Sulaiy source rock, but shifted to higher values. At present, most of the Sulaiy source rock has a TR between 45% and 80%.

Hydrocarbon Migration, Accumulation and Risk Assessment

In order to quantify petroleum migration and accumulation, a four-dimensional (x, y, z and time) reconstruction is required for the most prominent migration pathways. Lithological and fluid properties in the sedimentary succession have to be reconstructed as a function of the pressure and temperature history of the basin. Depth-dependent permeabilities are calculated for all lithologies and fault properties have to be implemented as well. All petroleum flow simulations in this study were performed using the hybrid migration method implemented in PetroMod. The hybrid migration is a PetroMod proprietary method using Darcy Flow and Flowpath algorithms as well as a simplified invasion percolation calculation. Darcy Flow describes multi-component three-phase flow, based on relative permeability and capillary pressure. Flowpath takes only buoyancy-driven migration into account. Invasion percolation is driven by a cell-based buoyancy and capillary pressure. Time control is ignored and the petroleum volume is subdivided into small, finite amounts. The hybrid method combines flow path-based migration in high-permeability materials and Darcy Flow migration in low-permeability layers (Hantschel and Kauerauf, 2009).

The studied sedimentary sequence has a regional evaporite layer (Gotnia), which has been seen as an unfaulted seal in the seismic sections. Furthermore, several claystones have been deposited from the late Hauterivian onward and also act as active seals. Due to the fact that the Sulaiy source rock occurs directly above the impermeable Gotnia Formation, hydrocarbons will be expelled from the source rock upward into younger reservoir layers, because the Gotnia seal will prevent any downward migration, even if overpressures would have occurred. The model only predicts low to moderate excess hydraulic pressures (up to 11 MPa) for the post-Gotnia formations, but high overpressures for the pre-Gotnia. Moreover, the Gotnia seal probably prevented any migration from the sequences below.

The modelled hydrocarbon migration pathways are shown in Figure 12a. The most common migration pathways are in the vertical direction, i.e. migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq almost directly overlie the source rocks (Figure 2). In addition, the migration vectors are always toward the anticlines and then towards the shallowest parts of these anticlines, where the calculated petroleum accumulations exist (Figure 12a). It is noteworthy to mention that the presence of some minor sub-vertical faults, which are visible in the seismic data (Figure 3), could also support the conclusion on a major vertical migration; however, assignment of fault properties (open versus closed) is difficult. The migration toward the rims of the model shown in Figure 12a indicates that there might be possible petroleum accumulations in structures outside of the borders of the study area, i.e. western Basra, northern Kuwait and southwestern Iran. Figure 12b shows the modelled drainage areas, migration pathways and their relation to the petroleum accumulations in one of the major accumulations, the Shu’aiba reservoir.

Figure 12b shows the modelled petroleum accumulations within two different reservoirs, i.e. Shu’aiba and Mauddud. The general distribution of reservoirs mimics the known reservoirs quite well and in particular the modelled accumulations at Rumaila North and South, Zubair, West Qurna, and Ratawi are known to exist in reality. However, the sizes of the petroleum accumulations are smaller than the real accumulations, especially with respect to the fields of Zubair and West Qurna. This is partly related to the fact that not all drainage areas are completely within the study area. Even more important is the usage of the “correct” kinetics, since the Yamama kinetics presented above show a lower conversion compared to the published Type II-S kinetics of Lewan and Ruble (2002). Furthermore, the 3-D model predicts an accumulation to the south of the Ratawi oil field, which is not assigned in the oil fields map of Basra (Figure 1). This could be an interesting target for future petroleum exploration, when the structures are confirmed by new seismic surveys. It should be kept in mind that the seismic coverage is poorest in the southern part of our study area and thus uncertainties are largest there. The model suggests also large petroleum accumulations within the Mauddud reservoir, although it has been mentioned by Ibrahim (1983) that it has no producible oil in southern Iraq. This might be related to the permeability of the upper-shaly member of the Nahr Umr Formation, which acts as a seal rock.

The accumulated hydrocarbons in the Lower Cretaceous reservoirs in the Basra area are very well preserved and not degraded, as consistent with our model predictions. In such areas where many compacted shales are present and major open faults are missing, intense biodegradation or water-washing affects are not expected, because water circulation in the basin is restricted. In addition, the accumulations occur at relatively great depths, where temperatures greater than 80°C prevent biodegradation. This is also supported by the results of Abeed et al. (2012), who described more than 30 oil samples from different horizons and different oil fields of Basra as non-biodegraded crude oils.

Due to the small number of exploration wells that penetrated the pre-Gotnia horizons in the Basra region, there is little known about these successions. In northern Iraq and the middle of the Mesopotamian Basin where the Jurassic has been better explored, the Jurassic Najmah/Sargelu succession is mature with excellent source rock characteristics (Al-Ameri et al., 2008; Al-Khafaji, 2010). Since the same Middle Jurassic palaeodepositional environment prevailed in the southern Mesopotamian Basin (Murris, 1980), we think that the Najmah/Sargelu succession in the Basra region has a high hydrocarbon accumulation potential and probably a higher maturity (Abeed et al., 2011). Therefore, the pre-Gotnia successions could be promising for light hydrocarbon and/or gas exploration.

In general, the available 2-D seismic data images the main anticline structures of the study area. However, the 3-D surfaces were constructed using an interpolation method, which causes uncertainties in our interpretation, especially in areas with less detailed seismic data and less well control. In addition, seismic data implies the absence of major faulting in areas of good data coverage, while the occurrence of faults might be underestimated due to the lower density of data in some parts of the study area. This uncertainty also regards the occurrence of faulting of the Gotnia Formation, which is not affected by faults along seismic profiles. The existing data indicates that there are not many brittle deformation features, except for some minor faulting in the core parts of anticlines and above. Strong changes of this setting are not expected in areas of low data coverage, but would greatly influence model predictions.

The entire succession above the Yamama/Sulaiy source rocks is at a very early maturity stage and has not significantly contributed to the petroleum generation in the basin. In contrast, the Upper Jurassic–Lower Cretaceous succession is partly at the stage of oil generation and most of its petroleum generation potential has been realized. According to the EASY %Ro equation of Sweeney and Burnham (1990), the Sulaiy source rock is within the late oil generation stage at present day. Due to the high maturity of the pre-Gotnia succession, light hydrocarbons and/or gas are expected in these reservoir rocks, if appropriate source rocks exist.

The most important oil traps in the study area are anticlines, which were generated by long-term, gentle tectonic compression. In general, the complete succession is almost unaffected by major faults. The high efficiency of the un-faulted Gotnia is now supported by seismic interpretation, which had been already deduced from geochemical investigation of the oils (Abeed et al., 2012).

The most common migration pathways of hydrocarbons are vertical upward. In addition, the migration vectors are towards the anticlines and then towards the shallowest parts of these anticlines. The efficiency of Gotnia seal prevents any downward migration. As indicated by the modelling results, there are outflows of hydrocarbons out of the study area and possible petroleum accumulations in structures in adjacent areas, i.e. northern Kuwait and southwestern Iran. This most likely also concerns the area to the west of Basra.

The authors are grateful to the Ministry of Oil, Oil Exploration Company, and the South Oil Company of Iraq for providing the data of this study and helping with respect to the interpretations of some seismic sections. We also appreciate the help of the German Research Centre for Geosciences, Potsdam, for analysing the bulk kinetics of the source rock samples. We are grateful to the two anonymous reviewers for their valuable comments, to GeoArabia’s Assistant Editor Kathy Breining for proofreading the manuscript and GeoArabia’s Nestor ‘Nino’ Buhay IV for designing the final version of the figures. Finally, the first author expresses his sincere gratitude to the German Academic Exchange Service (DAAD) for financial support.


Qusay Abeed is currently a PhD student at the Institute of Geology and Geochemistry of Petroleum and Coal, RWTH-Aachen University, Germany. He received his BSc in Geology in 2002 and then his MSc in Petroleum Geology in 2006 from Baghdad University, Iraq. He has published several papers on the petroleum systems of southern and northern Iraq. His main interest is the field of petroleum geology and organic geochemistry of source rocks and petroleum, as well as petroleum system analysis.


Ralf Littke is Professor of Geology and Geochemistry of Petroleum and Coal at RWTH Aachen University, Germany. He holds a diploma degree in Geology and Doctorate from Bochum University, Germany, where he worked in the field of sedimentology and coal petrology. Current research interests include dynamics of sedimentary basins with special emphasis on temperature and pressure history as well as unconventional gas reservoirs.


Frank Strozyk is a third-year post-doc researcher who joined the Geological Institute at RWTH Aachen University in 2009. Having explored submarine landslides and their consequences in the eastern Mediterranean he was a co-leader of geophysical data acquisition on two offshore research cruises during his PhD studies at the Marum-Center for Marine Environmental Sciences, Bremen. The focus of his post-doc studies are now the South Atlantic post-breakup margin analysis as well as Zechstein intra-salt deformation structures on-and offshore the Northern Netherlands. Frank further supports seismic interpretation and structural modelling in several other projects at RWTH Aachen University and gives lectures in 3-D seismic interpretation, structural modelling, and field mapping.


Anna Uffmann graduated from the Department of Applied Earth Sciences at RWTH Aachen University, Germany in 2008. For her diploma thesis she did fieldwork in northwest Namibia on Cenozoic raised beach deposits. Anna is now a fourth-year PhD student at the Institute of Geology and Geochemistry of Petroleum and Coal at RWTH Aachen University. Her current research focuses on petroleum source rocks, petroleum system modelling, basin analysis and gas shales. She also worked for IES, Schlumberger as a Software Tester and teaches a practical course in basin modelling.