The Kurdistan Region of Iraq has witnessed extraordinary levels of exploration activity since the first exploration well to be drilled in over two decades was spudded in 2005. Since then almost 200 wells have been drilled encountering recoverable reserves estimated to be in excess of 15 billion barrels of oil equivalent. Whilst the region is in close proximity to many of the giant and supergiant fields of Iran and Iraq, the reservoirs in which discoveries have been made are largely different. In Iraq a large percentage of discovered reserves reside in Cenozoic and Cretaceous sediments capped by Cenozoic evaporite sequences. Over much of Kurdistan, particularly the north and northeastern parts of the region, Cenozoic strata are absent.
A decade ago many were doubtful that significant quantities of hydrocarbons could be trapped in the absence of the Cenozoic evaporite sequences. Furthermore, whilst the presence of large surface structures and significant oil seeps were encouraging to some, to others it fueled concerns about trap leakage. Today the majority of the surface anticlinal features in Kurdistan have been drilled, but remain to be fully evaluated. Almost all of the exploration activity in Kurdistan has taken place on 2-D seismic with vertical exploration wells. In the last few years, a number of 3-D seismic surveys have been acquired and these will undoubtedly lead to production and reserve enhancements in parallel with increased subsurface complexity.
Following a decade of exploration, three fields have been fully appraised and have a reasonable early production history: Tawke, Taq Taq and Khurmala. Reserve additions in the Tawke Field have been significant as a result of increased production performance due to better than originally anticipated reservoir properties, better pressure communication and additional reserves found in older reservoirs. It is probable that similar trends will occur in other fields and discoveries.
Whilst a small number of horizontal wells have been drilled, advanced techniques used for producing from tight fractured carbonates such as multilateral wells, hydraulic fracturing, selective completions, proping and water injection have not as yet been used in the region. Almost all wells in Kurdistan have been drilled on surface or near subsurface structures within the foreland or the fold belt. Some wells have drilled through thrusts, more often by accident as opposed to on purpose. There have been virtually no dedicated wells for pure sub-thrust plays or stratigraphic traps although hydrocarbons have been found below significant thrusts and also beyond apparent structural closure in some structures.
Challenges remain in what is a structurally complex and recently deformed region. High levels of exploration and appraisal activity persist and new pipeline infrastructure is under construction. It is likely that the Kurdistan Region of Iraq will develop to become an important contributor to world oil and gas production. This paper aims to summarise the first decade of exploration and appraisal activity in Kurdistan Region of northern Iraq. Due to the paucity of technical papers on this subject, this document draws upon the authors’ own knowledge and material published by companies operating in the region.
This paper is considered to be the first to provide a comprehensive review of exploration, appraisal and production activities in Kurdistan Region of Iraq (Kurdistan) since the region ‘opened’ in 2003. Kurdistan has become one of the most active onshore hydrocarbon provinces in the world with production rising to over 400,000 bopd (barrels of oil per day) and newly discovered reserves in excess of 15 billion barrels.
The paper reviews the licensing and exploration activity since 2003. It details some of the challenges of drilling in this emerging fold-and-thrust belt. A suite of maps document all the key discoveries and producing fields and also detail wells that have been unsuccessful with possible reasons for their failure. The paper concludes with a summary of current activity and future trends, which are likely to shape Kurdistan over the next decade.
There are few technical publications specific to Kurdistan and much of the material in this paper is drawn from published competent persons reports and corporate presentations, some of which are no longer available. It is hoped that this paper will provide a useful summary of the first full decade of exploration activities in the Kurdish region.
LICENSING AND EXPLORATION ACTIVITY IN KURDISTAN
Activity Prior to 2003
The first exploration well in the Middle East was drilled in 1901 on the Chia Surkh structure close to the present-day border with Iran in the southeastern part of Kurdistan (Figure 1). The well was located on a hill close to an active oil seep and it was abandoned with oil shows after drilling to 710 m in depth. Between 1905 and 1922 four more wells were drilled on the structure, some finding oil shows with none of them drilling below 800 m (Aqrawi et al., 2010). During the next 83 years (1922–2005) less than 30 wells were drilled in Kurdistan and these only targeted seven structures; Chia Surkh, Pulkhana, Kor Mor, Khurmala Dome, Chemchemal, Taq Taq, Demir Dagh and Jabal Kand (Figure 2).
During this same period a number of significant discoveries were made both in the central part of Iraq and in the Zagros of Iran. The first significant discovery in the Middle East was made in 1908 at Masjid-i-Suleiman in the Zagros of Iran (Sorkhabi, 2008; Figure 1). The Kirkuk Field was discovered in 1927 by the Turkish Petroleum Company (later to become the Iraq Petroleum Company, IPC). The discovery well (Baba Gurgur-1) encountered oil in the Cenozoic and blew out, taking a number of days to control. The discovery well was located on a surface anticline and close to a natural gas seep: “The Eternal Fire of Baba Gurgur” (father of fire), which is believed to have been active for more than 4,000 years. Some of the other discoveries in Iraq include: Qaiyarah (1928), Rumaila (1953), West Qurna (1973), Majnoon (1975), East Baghdad (1976) (Figure 1). The Khurmala Dome, at the northwestern end of Kirkuk, was first drilled pre-second World War but it was plugged and abandoned, along with other wells, as European troops approached Egypt in the early 1940s. During the Iran-Iraq war (1980–1988) exploration and appraisal drilling continued in Iraq, albeit at a much reduced pace. A comprehensive summary of the history of oil exploration in Iraq is given in Aqrawi et al. (2010).
The Taq Taq structure in the central part of the Kurdistan Region of Iraq (Figure 2) was first drilled in 1960 and drilling was suspended in April 1961 after setting 95/8 inch casing in the top of the Upper Cretaceous Shiranish Formation. This followed the issuance of Public Law 80, which took away 99.5% of the IPC’s ownership (Falola and Genova, 2005). In 1964, the government established the state-owned Iraq National Oil Company (INOC) to develop the concession areas taken over from IPC. Sixteen years later in 1978, INOC decided to re-enter the Taq Taq-1 Well and it was deepened to the Lower Jurassic, testing oil from a number of formations within the Cretaceous. In 1979–1980, INOC contracted a rig to drill more wells on the discovery (Taq Taq-2 discovered oil in the Eocene Pila Spi Formation), but tensions between the Kurds and the Baath regime, coupled with the outbreak of the Iran-Iraq war, led to a cessation of drilling. In 1994, the Kurdistan Regional Government (KRG) tested and completed Taq Taq-1 and Taq Taq-2 signalling the first production from Kurdistan. Prior to the Iraq War of 2003, the Turkish company Genel Enerji AS signed the first production sharing agreement in Kurdistan (KRG, 2002). This contract was for the Taq Taq Field. Soon after another Turkish company, Petoil Petroleum, together with US-based Prime Natural Resources were allocated areas to explore (KRG, 2003). These contracts signalled the start of a new phase of exploration activity in Kurdistan.
Following the Iraq War in 2003, more international oil companies started to approach the KRG and undertake technical work in the Kurdish autonomous region. At this time, neither the Constitution of Iraq nor the Oil Law had been passed and there were ongoing disputes regarding revenue sharing between the KRG and the Iraqi Central Government (ICG). The Kurdish Ministry of Natural Resources (MNR), which at this stage comprised only a handful of people, drew up a ‘block map’ of the region nominally assigning one surface structure per block. The 48 blocks were ranked into low, mid and high risk and fiscal terms varied to reflect perceived technical risk. In addition, 8 lettered blocks were delineated along the border with Turkey and Iran (Figure 2).
In addition to the political risk, there was a paucity of subsurface technical data specific to Kurdistan and no service sector. Prior to the Iraq War in 2003, very few exploration wells had been drilled in Kurdistan (Figure 2). There was virtually no seismic data, and what wells and seismic data were available, avoided the more mountainous areas and were generally close to the existing Iraqi oil fields. Moreover, even if one knew of the possible existence of subsurface data, getting access to it was often extremely difficult.
The Iraq Lexicon (van Bellen et al., 1959-2005) has proven to be an invaluable source of data on the lithostratigraphy of Iraq, incorporating four decades of field surveys and investigations. Local geologists and students have produced theses on the surface structure, stratigraphy and hydrogeology. Whilst providing a rich source of information, in the absence of an oil industry, there had been little focus on petroleum systems and what little data was available needed extrapolation into the subsurface.
Early Award Process and Work Programs (2002–2006)
There were no data packages and there was no formal bidding process in the early development of the oil industry (2002–2006). The negotiation between the Ministry of Natural Resources and oil companies largely revolved around the location of the block(s) in question and the cash bonus payable on entry. Work programmes generally consisted of geological fieldwork, 2-D seismic acquisition and one exploration well to be completed within the first 3 years, plus a second exploration well within the second two-year term of the Production Sharing Agreement (PSA, sometimes referred to as a Production Sharing Contract, PSC). This was a tight time frame given the paucity of infrastructure and service sector support in the early years. By 2007 the Ministry of Natural Resources had produced a ‘formal’ block map (Figure 2) and indicative fiscal terms. Competition for blocks was great, particularly in the period from mid-2007 to mid-2008 when almost half of the available blocks were signed. Block awards favoured those companies that were willing to invest resources in early fieldwork, data collection and its analysis, and make early commitments to the KRG, not to mention taking some political and technical risk. Despite the discontinuity of almost three decades of exploration inactivity and the proximity of Kurdistan to the world-class oil fields discovered in Iraq, Iran and northeast Syria; there were still technical concerns. Kurdistan was classed by many as frontier, wildcat territory.
Significant oil seeps are known in Iraq (e.g. above Kirkuk) and are present across Kurdistan. In some cases flows of oil can be seen on the surface. Significant oil seeps are evident above the Tawke Field (Carstens, 2006); at Gelli Keer above the Shaikan Field (Figure 3a); at Gelli Zonta (Figure 3b) and in the Bekhme Gorge (Csontos et al., 2011). Oil seeps have also been recorded above, or in close proximity to, many of the prominent surface structures such as Bina Bawi, Sangaw, Chia Surkh, Kurdamir and Qara Dagh (Figure 4).
In some areas, particularly during the summer months, oil can be seen seeping from outcrop-scale fissures, vugs, bedding planes and pores. Some of these natural seeps are thought to be a result of leakage via faults (e.g. above the Tawke Field and at Gelli Zonta), whilst some of the oil-saturated carbonates seen at the surface are almost certainly exhumed oil accumulations (e.g. the Eocene Pila Spi Limestone above the Shaikan Field).
Whilst a number of workers were encouraged that the seeps demonstrated the presence of an underlying mature source rock, others were concerned about traps having been breached and hydrocarbons having leaked away. Significant leakage has undoubtedly occurred and is still occurring today. However, large hydrocarbon accumulations have since been discovered below many of these seeps suggesting that the rate and volume of seepage, in some structures, is largely insignificant compared to the volumes that have been generated, trapped, and are probably still being generated today.
Exposure of pre-Cenozoic sediments and in particular the absence of the Miocene Fars Group evaporites was for a number of workers, a ‘play killer’. It was thought that a Fars Group ‘super seal’ was required to preserve subsurface accumulations and as such, some companies were discouraged by the presence of Cretaceous and Jurassic sediments at surface with the belief that no older accumulations were possible. This was a concern in fact, first raised in the early 1950s (Baker and Henson, 1952). Consequently, many companies avoided the fold belt in Kurdistan altogether and focused on the Cenozoic-covered plains (Figure 4). With the benefit of almost a decade of exploration activity it is clear that a number of very competent seals (shales and anhydrites) exist in the pre-Cenozoic stratigraphy and these have facilitated the presence of significant hydrocarbon accumulations in the Cretaceous, Jurassic and Triassic. Although probably beneficial, there is no essential requirement for a Cenozoic ‘super seal’ (Figure 5).
Early entrants came armed with commercially available (and sometimes free) satellite imagery such as Landsat and Google Earth. Published geological maps gave an excellent overview of the surface geology of Iraq and Kurdistan. However, they were at times inaccurate, particularly in the more remote and structurally complex areas. A typical workflow for this data is given in Figure 6. Important aspects of this early work were to calibrate satellite image data, to identify the main structural elements and their possible impact on the structure and stratigraphy, and to establish the age of the oldest exposed sediments in the core of the anticline in question. Given the intensity of weathering, recrystallisation and lithologic variation, biostratigraphic age dating was often indeterminate. Even where good fossil recovery was obtained there were often differences of opinion as to precise age dates and lithostratigraphic assignation.
Geochemical evaluation of potential source rocks and surface oil occurrences provided an indication of thermal maturity and source potential. It was considered that the Middle Jurassic Sargelu Formation and the Upper Jurassic Naokelekan Formation had yielded the bulk of the oil that had charged reservoirs in the Mesopotamian Basin and Zagros fold belt (Pitman et al., 2004). It was also clear that compositionally distinct oils, considered to have been sourced from the Triassic, have also been generated in northern Iraq and Kurdistan (Al-Ameri and Zumberge, 2012).
Once awarded acreage, operators generally undertook additional field mapping, sampling and structural reconstructions (Figure 7). The aim of these studies was to develop a robust geological and structural model of the acreage and thus enable an initial assessment of the hydrocarbon prospectivity. Most of this early work had to be undertaken within the first 12 months so that 2-D seismic acquisition could be undertaken during the summer months of the second year and drilling in the final year of the first three-year term. 2-D seismic data has now been acquired over all blocks except for those in the far east/northeast beyond the main Zagros thrust. All initial new field wildcat exploration wells in Kurdistan have been drilled on 2-D seismic data. These lines show considerable variation in data quality, which is often seen to degrade where hard carbonates are exposed at the surface and in regions of structural complexity. Beyond the mountain front this has frequently meant that the crests of anticlines are often poorly imaged but the flanks, with Cenozoic cover, have good imaging. With nearly all exploration wells being crestally located this has often meant some uncertain and difficult drilling (Figure 8).
In the absence of seismic data, the ‘Busk method’ (also known as the concentric arc method) was used in an attempt to extrapolate surface dip and strike measurements into the subsurface (Busk, 1929). Whilst this proved to be a useful geometric exercise, it assumed stratigraphic uniformity and was unable to take into account any significant tectonism or crestal accommodation in box fold type structures.
New Drilling in Kurdistan
Although a limited number of production sharing agreements (PSA) on existing discoveries were signed in 2002 and 2003, the first new exploratory drilling was undertaken by Norwegian company DNO (Det Norske Oljeselskap AS) who signed a PSA with the KRG in mid-2004 (DNO, 2004; KRG, 2004). Following fieldwork, the company acquired 450 km of 2-D seismic data and spudded the first well in Kurdistan for over a quarter of a century on November 28, 2005 (DNO, 2005a). The well was located within an elliptical anticlinal surface feature in the northwestern part of Kurdistan (Figure 9). By late 2005 it was announced that Tawke-1 had encountered 24° API oil at a depth of 350 m (DNO, 2005b). By mid-2006 the well had drilled to a total depth of just over 3,100 m in the Jurassic and flowed at a restricted rate of 5,000 bopd from Cenozoic limestones (Harstad et al., 2010).
Later that same year, the first new exploration activity took place on the Taq Taq Field under the operatorship of the newly formed Taq Taq Operating Company (TTOPCO) a joint venture between Genel Enerji AS and Addax Petroleum Corporation. 2-D seismic data acquisition commenced in early 2006 and the first new well (Taq Taq-4) spudded in May 2006 reaching total depth in December 2006. The well flowed an aggregate of 29,600 bopd from three different Cretaceous reservoirs (Addax Petroleum, 2009).
The success of Tawke and Taq Taq accelerated competition in what was already a competitive environment. By early 2006 seven PSAs had been signed and six companies had commenced exploration activities (Figure 9). Within a year almost half the blocks south and west of the mountain front had been signed, each one to a new operator; there were now some 13 operators on 15 blocks. In an eleven-month period between September 2007 and June 2008 some 18 new PSAs were signed (Figure 9). Whilst some of the entrants were ‘small’ in terms of their market capitalisation, some larger oil and gas companies had by this time negotiated contracts (e.g. MOL, Reliance, Hunt and Talisman). Blocks were signed across the region with little apparent preference, by industry as a whole, for either the northern or the southern part of Kurdistan. Whilst most companies came in search of oil, some focused on gas and associated liquids. In early 2007, Dana Gas entered into agreements with the KRG to develop, process and transport natural gas and condensate from the Kor Mor gas field (Dana Gas, 2014). This was the first gas development in Kurdistan.
By late 2009 around 20 new exploration and appraisal wells had been drilled in Kurdistan. New discoveries included; Tawke, Bina Bawi, Sarqala, Miran, Barda Rash, Shaikan, Kurdamir, Jabal Simrit and Bijell. Continued expansion of the service sector (drilling and logging contractors) and improvement in infrastructure (roads, communications, local work force) has helped maintain significant drilling activity from 2010 onwards with an average of over 20 exploration and appraisal wells drilled per year (Figure 10). This also coincided with the third year of the first term for many of the PSAs that had been signed in 2007 by the end of which almost all companies were required to have drilled at least one exploration well.
The current block map shows that of 64 blocks, 49 are licensed with 25 different operators (Figure 11). Relinquishment, of whole blocks and part blocks, is now resulting in a steady turnover of acreage. Companies that signed PSAs in the early years (2003–2006) were largely dominated by smaller players. Over time and with continued success, larger independents, majors and super majors have entered the region and have begun exploring. In parallel, some of the smaller players have either exited without success or have been ‘taken over’. Although there are a few ‘open’ blocks, the region has seen active deal flow with some new entrants willing to buy into existing discoveries or exploration blocks. Of the 64 licensed blocks, over half have significant discoveries and technical success rates for new field wildcats, as defined by the authors as flowing in excess of 500 bopd on test, are estimated to be around 63%.
In total over 20,000 line-km of new 2-D seismic data have been acquired since 2005. Given that the majority of surface features are elongate anticlines, the typical 2-D grid for most operators has been to acquire dip lines spaced 2–5 km apart and a more limited number of strike lines; one along the axis/crest of the structure and one either side. Where possible these lines have generally followed existing roads and tracks, with bulldozers used to navigate more difficult terrain. Where the terrain is more benign and Cenozoic shales crop out at the surface, vibroseis acquisition has been performed with good effect. In such areas seismic data quality is generally good as a result of better coupling and signal penetration. In the more mountainous areas, acquisition with a dynamite source is often required. In some extreme cases, seismic cables have needed to be positioned by mountaineers (Addax Petroleum, 2008; Vast Exploration, 2009). In such areas, where surface sediments comprise hard, fractured and karstified carbonates, the seismic data are usually much poorer due to near-surface dispersion of the signal (Figure 8).
To date around 20 3-D seismic surveys have been acquired in Kurdistan totalling over 6,350 sq km of 3-D data (Figure 11). Most of these surveys have been acquired post initial discovery and the majority in the last 3 years. The Tawke and Taq Taq 3-D surveys have undergone pre-stack depth migration (PSDM) reprocessing and the Shaikan 3-D has also been reprocessed pre-stack. In each case image quality in the core of the anticline has been much improved. 3-D seismic data is also helping to image local variations in reservoir thickness and in some cases there are indications that areas of better quality reservoir can be mapped on the 3-D seismic (DNO, 2011). In the Kurdamir Field a horizontal well has been planned and positioned in an area predicted to have best quality porous reservoir and high fracture density (Western Zagros Resources, 2015b).
It is very likely that these data will reveal additional complexities that have thus far not been imaged on sparse 2-D seismic. One of the key factors in obtaining good quality seismic data, in addition to surface geology, are the acquisition parameters, not least of which the shot array and depth/volume of dynamite used during acquisition. Careful testing prior to acquisition has proven to be extremely helpful in the region.
The eastern and northeastern parts of Kurdistan are mountainous and become increasingly so approaching the main thrust towards the northeast bordering Iran and Turkey (Figure 12). In this region wells have been drilled at high elevations, which often suffer extremes of weather during the year. The highest elevation structures drilled to date are all located in the northern part of Kurdistan and include wells drilled on Sindi Amedi, Sarsang, Shakrok, Harir and Safeen, all of which are mountainous areas with drilling having taken place in excess of 1,400 m above sea level. The highest elevation well to be drilled in Kurdistan to date is the Shireen-1 Well in the Dinarta Block (Hess/Petroceltic), which spudded in June 2014 at an elevation of 2,094 m above sea level.
Not only can access to these remote hilltop locations be challenging but conditions in winter can be severe with temperatures going well below zero for protracted periods with snow falls and drifts further complicating operations (Preining and Nazhat, 2013). In some cases winter lightning strikes on rigs, despite conductors, have temporarily halted operations (Gulf Keystone, 2012). Winter weather and associated problems, are considered to be one of the biggest contributors to lost time in wells that have been drilled in the more mountainous parts of the region.
Given recent structuration of brittle carbonates and seasonal extremes of temperature it is no surprise that where carbonates are exposed, near-surface sediments can be highly fractured, weathered and karstified. Top-hole sections of wells in these areas, mainly in the more mountainous northern and eastern parts of Kurdistan, have suffered severe mud losses with significant intervals often drilled ‘blind’ with no returns whatsoever. Losses in excess of 450,000 barrels of mud were recorded in the Shaikan-1 Well (Gulf Keystone, 2014a) and over 380,000 barrels of mud were lost during the drilling of the Swara Tika-2 Well (Preining and Nazhat, 2013).
In some extreme cases, near-surface conditions have led to rig tilting and partial collapse/jamming of the top-hole drill strings necessitating re-spudding of wells. Over the last few years, companies operating where these conditions are likely to occur are successfully using air and foam drilling to good effect. This technique, widely used in the Rocky Mountains of the US, reduces the hydrostatic pressure in the wellbore and reduces lost circulation in low-pressured formations, which are encountered above the water table. Below the water table, in potential hydrocarbon-bearing zones, operators in Kurdistan have largely used water-based mud systems, which are at times nitrified to further reduce mud weight. Managed Pressure Drilling (MPD) technology has also been used to good effect to optimise and improve the efficiency of the drilling process. The MPD technique aims to control the annular pressure in the wellbore, and in doing so minimise continuous influx of formation fluids to the surface, and maintain wellbore integrity (Preining and Nazhat, 2013; Driedger, et al., 2013).
Clearly, significant losses in potential reservoir zones can compromise subsequent formation evaluation and testing. Moreover, significant losses also necessitate large volumes of water. This has at times placed a strain on available water resources with almost all operators needing to drill dedicated water wells for their drilling activities. Often, water is piped uphill from dedicated water wells through a number of pumping stations. In some cases operators have needed to truck additional water to the wellsite, which can delay operations. If in the future, water injection is required in any large measure then this could place a strain on the region’s water resources. This is not a problem unique to the Kurdistan Region of Iraq; in the Rumaila, West Qurna and Zubair fields in the southeastern part of the country, it is planned that 5.2 million barrels a day of sea water will be piped from the Gulf and used for water injection to sustain production (CH2M Hill, 2013).
The majority of wells in Kurdistan have been drilled to measured depths of between 3,000 and 4,500 m. Fewer than 10 wells have drilled deeper than 5,000 m and very few have yet penetrated the entire Triassic succession to reach the Permian. Moveable hydrocarbons have been encountered at depths from as shallow as 350 m in the Tawke Field (DNO, 2005b) to over 4,000 m in the Sarqala Field (Western Zagros Resources, 2014a, b). It has not been uncommon for exploration wells in Kurdistan to take in excess of 6 months and in a few cases over a year to drill and test. Difficulties have included: (1) delays due to winter weather; (2) severe losses in fractured and karstified formations; (3) lack of available water for drilling activities, (4) H2S concentrations that can be in excess of 25% in the gas phase (Table 1); (5) slow drilling through hard carbonates; (6) difficulties in drilling through the Lower Fars (more usually in the southern part of the region) which is often overpressured; and (7) the logistics of drilling in an emerging fold-and-thrust belt province. Given the number of potential reservoirs, and frequent ambiguity of petrophysical results, operators often undertake multiple drill-stem tests (usually at least 3 and in some cases up to 10) adding significantly to the duration of operations.
In the north of the region where Cenozoic strata are largely absent over many of the drilled structures, typical casing programs have been designed so as to isolate units of differing pressure with casing points often separating the Cretaceous and Jurassic. In the southern part of the region, where thick Cenozoic sediments are present (and are often the target), pressure regimes are often more complex and at times have required up to 6 strings of casing to reach total depth (Western Zagros Resources, 2010a). A further complexity, thus far more prevalent in the southern part of the region, is that of abnormal pressured formations (both under-pressured and over-pressured). The Sarqala-1 wildcat well encountered pore pressures over 17.5 pounds per gallon (ppg) (2,100 kg/m3) mud weight equivalent pressures below the Lower Fars top seal (Western Zagros Resources, 2011). The Qara Dagh-1 Well encountered pressures of 9,000 psi in the Shiranish Formation at a depth of 3,500 m (Vast Exploration, 2011) (Figure 11).
Ideally, new exploration wells, in relatively unknown stratigraphy, should be designed to have contingency for additional casing strings should they be required.
Although all drilling in Kurdistan has been onshore and has been undertaken in the last decade, well costs have varied dramatically. A few wells have cost in excess of US $120 million (Kurdamir-1, Western Zagros Resources, 2010b) and some as little as US $7 million (Tawke-16, DNO, 2012a, b). Rig rates (for 1,500 HP units) have typically remained in the region of $30,000–35,000 per day (Gulf Keystone, 2014a). Where operators have in-country drilling experience and pressure/stress regimes are known, well costs have tended to fall over time. Moreover, companies with larger, established operations have also been able to tender more competitively further reducing costs. Well costs in the Taq Taq Field have varied from US $18.5 million to as little as US $3.7 million with average well costs falling from US $12.3 million for the first 7 wells to US $6.9 million for the next 6 wells (Genel Energy, 2012). Wells in the more mountainous areas often take longer and are generally more expensive than those on the plains.
The early discoveries in Kurdistan were made in sediments of Cenozoic and Cretaceous age (Tawke, Taq Taq, Chemchemal, Kor Mor, Pulkhana). Later drilling has tested progressively deeper targets and resulted in discoveries in the Jurassic and Triassic (Shaikan, Bijell, Swara Tika, Bina Bawi, Barda Rash). Only a limited number of wells have thus far drilled through the Triassic and reached the Permian, which is of course a significant reservoir target in the Middle East. The Upper Permian carbonates of the Chia Zairi Formation were penetrated in the Ber Bahr-1 Well and have the potential to form a viable exploration target in Kurdistan (Aqrawi et al., 2010). Albeit high risk, it is possible that if present, lower Silurian hot shales of the Akkas Formation might have sourced gas, as they have done in the western part of Iraq and eastern Jordan (Figure 5, Al-Hadidy, 2007).
Some of the early wells were drilled, but stopped short of now proven reservoirs; these are seeing a resurgence of activity. The Demir Dagh-1 Well, drilled in 1960, reached total depth (TD) at a depth of ca. 2,300 m true vertical depth sub-sea (TVDSS) in the Upper Jurassic having encountered hydrocarbons in the Cretaceous (Figure 2). In 2013–2014 the Demir Dagh-2 Well was drilled less than 2 km away to a depth of ca. 3,600 m TVDSS and encountered oil in additional Middle and Lower Jurassic targets (Oryx Petroleum, 2014a). Eleven wells have now been drilled on the field which measures approximately 9 km in length by 4 km in width and is estimated to have proven and probable oil reserves of 258 million barrels (Oryx Petroleum, 2015).
‘Deep’ wells are planned or in progress on the Bina Bawi, Tawke and the Miran discoveries. Drilling to such targets is likely to be challenging necessitating oversized shallow-hole sections and the contingency for mechanical sidetracks. In the Shaikan Field overpressure is common in the deeper Triassic section and mud weights up to 19 ppg were required whilst drilling (Gulf Keystone, 2014a). A recent well on the Shaikan Field (Shaikan-7) failed to reach its intended Permian target due to a number of mechanical failures in the course of the drilling operations (Gulf Keystone, 2014b).
DISCOVERIES AND PETROLEUM GEOLOGY
Some 40 new field wildcat hydrocarbon discoveries have been made in Kurdistan with two-thirds of these being located in the northern half of the Kurdistan Region (Figure 11). Of these discoveries, 12 have approved development plans and four of these (Tawke, Taq Taq, Kor Mor and the Khurmala Dome) have significant production histories. The bulk of the discovered resources are considered to reside in Cenozoic, Cretaceous and Jurassic strata with the Triassic strata thus far are considered to make a small, but important, proportion of overall discovered resources (Figure 13). Almost all of the hydrocarbons discovered in Cenozoic strata in Kurdistan are in the southern part of the region. Other than the Kor Mor and Chemchemal fields there have not been as yet any approved development plans for recently discovered fields in the southern part of Kurdistan.
The bulk of discovered oil reserves have been made in the northern part of the region between the Taq Taq and Tawke fields. This is thought to be due to the maturity of the Jurassic source rocks, which are optimally mature in the northern part of Kurdistan but considered to be more deeply buried and in the light oil to gas window in the southern part of the region due to the significant thicknesses of Cenozoic strata in this area (English et al., 2015). The northern area is also a palaeohigh (the Mosul High) so reservoirs are shallower and carbonates are perhaps more likely to be in shelfal facies (Aqrawi et al., 2010).
A number of companies are continuing to explore and appraise their fields whilst development is ongoing. DNO recently discovered additional resources in Jurassic strata below the existing Cenozoic and Cretaceous field (DNO, 2013a). Exploration drilling is ongoing in the Taq Taq Field (a Cenozoic and Cretaceous accumulation) for deeper prospective zones in the Jurassic and Triassic. It was recently announced that the Taq Taq deep well had encountered 300 m of gas condensate shows in the Jurassic (Genel Energy, 2014b). Given the recent entry of some players a number of exploration campaigns have only just commenced (e.g. ExxonMobil). It is probable therefore that similar levels of exploration and appraisal activity will continue for the foreseeable future with additional resources potentially discovered in deeper stratigraphy.
The Zagros Fold-and-Thrust Belt forms the northern and northeastern margins of the Arabian Plate (Alavi, 2004; Lawa et al., 2013). Over 50 years ago the northern part of Iraq was subdivided into different zones on the basis of structural complexity: the unfolded zone, the folded zone (low and high) and the nappe zone (Dunnington, 1958-2005). Within Kurdistan it is clear that the structuration is more complex beyond the mountain front and that approaching the main thrust the degree of thrusting and overturning of folds becomes more intense (Figure 4). However, the variation of structural style, even over quite short distances, within the region can be quite marked. The digital elevation images (Figure 12) display quite clearly the NW-trending anticlinal features in the southern and central part of Kurdistan. This “Zagros” trend continues for ca. 150 km within Kurdistan before dying out to the northeast of Erbil. Beyond this area, the structures have a marked WNW-ESE trend (“Taurus” trend). Some workers postulated the presence of SW-trending lineaments, which facilitate the change of principal stress of the Arabian Plate and influence regional subsidence through the Mesozoic (Jassim and Goff, 2006). As yet these possible deep-seated lineaments have not been seen on seismic data (Csontos et al., 2012). It is notable that there are also some structures that do not appear to follow the local structural ‘grain’ such as Tawke in the northwest of the region.
Structures generally range from 15–40 km in length and 2–5 km in width. Most are anticlines, which plunge both to the NW and SE (or W-E). However, very often structures converge and interfere with one another complicating the identification of structural closure. It is quite usual for structures to be asymmetric with one limb dipping more steeply than the other, although it seems equally common for structures to be faulted box folds with significant crestal faulting accommodating movement. Parasitic folds are frequently visible at outcrop reflecting possible deformation during fold growth.
How much of the accommodation has been taken up by thrust faults is uncertain. In particular, where postulated thrusts might decollé and how much strike-slip movement might have taken place along such lineaments is also uncertain. Beyond the mountain front, Palaeogene and older sediments outcrop (Figure 4). It is in this region, approaching the main Zagros thrust, that the degree of uplift and erosion is generally considered to become more severe (Figure 14). Shallow thrusts may well soleout on anhydrites and shales, which are developed within the Jurassic and Triassic. Further north, and close to the main thrust, there is evidence that structures have been overturned and both nappes and thrusted nappes have been identified. A number of wells have encountered repeat sections as they have passed through large reverse faults (e.g. Sheikh Adi-1A Well, Law et al., 2014, their figure 6.1, p. 54).
The majority of wells in Kurdistan, particularly in the northern part of the region, have been drilled on clearly visible surface structures. More often than not these are significant mountains and folds with marked elevation versus the surrounding terrain. Examples include Ber Bahr, Shaikan, Jabal Simrit, Harir, Bina Bawi, Miran and Qara Dagh. To the west of the mountain front, Neogene, Pleistocene and Holocene deposits have largely obscured deeper structures with the only evidence to their existence sometimes being where thrusts come to surface. This is particularly characteristic of the southern part of Kurdistan in the vicinity of the Kor Mor, Pulkhana, Shakal and Taza discoveries.
Almost all exploration wells have targeted either four-way dip closures or three-way closures against a significant fault (Figures 11 and 15). Whilst hydrocarbons have been discovered beyond apparent structural closure, no pure stratigraphic targets have thus far been drilled. One well, Gulak-1 in the Akri-Bijeel Block operated by the Hungarian company MOL, has been drilled to target sub-thrust potential. Small volumes of oil were produced on test from below the thrust (MOL, 2013).
It is clear that complexities exist both in terms of in-field reservoir facies variations and fluid distributions across structures. In the absence of 3-D seismic data and sustained production history such complexities might take time to be revealed. In the Taq Taq Field, different oil-water contacts have been observed, with the western flank of the structure having an oil-water contact some 60 m deeper than that seen in the east. This is corroborated by wireline pressure data, log and flow test data (Addax Petroleum, 2009). It is postulated that there has been strike-slip movement along faults at reservoir level (Garland et al., 2010). Tilted oil-water contacts are interpreted to be present in fields in Iran (A. Horbury, personal communication) and these are thought to be present as a result of the pressure gradient in the aquifer as a result of meteoric water influx from the higher parts of the Zagros. Although different fluid contacts are postulated to exist in matrix and fractures, no tilted contacts have been interpreted in Kurdistan to date.
Almost all hydrocarbon discoveries in Kurdistan have been made in carbonate reservoirs ranging from the Upper Triassic to the Upper Miocene (Figure 5). Comprehensive descriptions of reservoirs units in Iraq and Kurdistan are presented in Aqrawi et al. (2010) and van Bellen et al. (1995-2005).
To date there have been no hydrocarbon discoveries in Palaeozoic strata within Kurdistan. The Jabal Kand-1 Well was spudded in late 1981 (completed in mid-1983), the last well to be drilled in Kurdistan prior to the Tawke-1 Well in 2005 (Figure 2). The well reached total depth in the Lower Carboniferous Harur Formation (Figure 5). Although some Lower Permian reservoirs (Ga’ara Formation) were penetrated they were deemed to have flowed water (Gulf Keystone, 2009, their figure 3). The only Palaeozoic discovery in Iraq to date is in the Akkas Field, which has gas-bearing Ordovician sandstones (Khabour Formation), a play that extends into Jordan (Figure 1).
Late Triassic strata are represented by the Kurra Chine Formation, which consists of interbedded anhydrites with limestones, dolomites and shales. The section crops out in the northwestern part of Kurdistan (in the Gara Anticline) but recrystallisation and dissolution of evaporites has resulted in generally poor quality outcrops (Figure 16c). In the subsurface, the major anhydrite sequences are clearly visible on logging-whilst-drilling (LWD) and wireline logs.
The Upper Triassic, Kurra Chine is a reservoir in the Shaikan Field where flow rates of 11.2–20.4 million standard cubic feet gas per day (mmscfg/d) and 5,474 barrels oil per day (bopd) were achieved. The principal reservoirs are dolomites with porosities estimated to range from 7–15% whilst permeabilities are clearly enhanced by fracturing (Ryder Scott, 2011). Triassic strata are also hydrocarbon-bearing in the Swara Tika, Jabal Simrit, and Bakrman discoveries. In the Bina Bawi Field the Triassic is gas-bearing with an estimated hydrocarbon column in excess of 1,000 m (Genel Energy, 2013). Hydrocarbons that have been discovered in Triassic reservoirs are compositionally distinct, and believed to have been sourced from organic-rich layers within the Upper Triassic Kurra Chine Formation (Al-Ameri and Zumberge, 2012). It should be noted that there are difficulties with lithostratigraphic assignation between the Lower Jurassic Butmah Formation and the Upper Triassic Kurra Chine Formation. This complicates correlations, palaeogeographic understanding and petroleum systems analysis.
The principal source rock intervals that are presently considered to have sourced much of the oil in Kurdistan are the Middle to Upper Jurassic Naokelekan and underlying Sargelu formations (Pitman et al., 2004; English et al., 2015). These crop out in the northeastern part of Kurdistan where they are represented by a condensed sequence of argillaceous and bituminous limestones (Figure 16b). In the subsurface they provide readily identifiable marker horizons and they are also proven reservoirs in the Atrush Field in northern Kurdistan (Figure 11). In the Atrush Field, it is estimated that there is an 800 m hydrocarbon column in stacked Jurassic reservoirs including the Barsarin, Sargelu, Alan, Mus, Adaiyah and Butmah formations. These reservoirs have a mix of matrix and fracture porosity. On test, some of these reservoirs have produced at rates up to 15,000 bopd (Shamaran Petroleum Corporation, 2013). In the Shaikan Field, over 65% of the best-estimate total oil-in-place is interpreted to reside in Jurassic strata (Sargelu, Mus and Butmah formations; Law et al., 2014).
Cretaceous reservoirs have proven to be highly productive and significant volumes have been produced from the Cretaceous in both the Tawke and Taq Taq fields where they provide the primary reservoirs. In all cases these reservoirs comprise low-porosity limestones and dolomites, which are heavily fractured. In Taq Taq, the Shiranish and Kometan formations have matrix porosities in the region of 3% but the units are fractured with permeabilities in the range of 200–10,000 milliDarcies (mD). These reservoirs form single-porosity, single-permeability systems. Aggregate well test rates from these intervals range from 16,570–19,180 bopd in the Taq Taq-8 Well. The underlying Qamchuqa Formation has higher matrix porosity (in the region of 8%) and similarly high fracture permeabilities.
This reservoir unit forms a dual-porosity, single-permeability system. In the Taq Taq-4 Well aggregate flow rates of 12,920 bopd were achieved on test (Addax Petroleum, 2009). In the Shaikan Field the Lower Cretaceous Sarmord Formation comprises dolomites and limestones, which have porosities in the range 10–15% (Ryder Scott, 2011). The Shaikan-4 Well also flowed oil from the Chia Gara Formation at rates of 130 bopd (Law et al., 2014, their page 22).
The Eocene Pila Spi Formation (and its lateral equivalents the Avanah and Jaddala formations) are important reservoirs in the Taq Taq, Kurdamir and Kirkuk fields. In the northern part of Kurdistan it is largely absent or frequently exposed forming prominent ridges around structures; a useful surface feature for satellite mapping. In Gelli Keer (Oil Gully in Kurdish) above the Shaikan Field, the Pila Spi Formation limestones are oil-saturated and actively seeping hydrocarbons. It is possible that this represents an exhumed oil accumulation at this location (Figure 3a). In outcrop, the Pila Spi Formation is a white, chalky, crystalline limestone, which is at times dolomitised. It is considered to represent deposition in a lagoonal setting. In the Taq Taq Field the Pila Spi Formation is a minor reservoir, some 110–130 m in thickness, and it flowed 2,150 bopd on test (Garland et al., 2010).
Two of the most significant discoveries in the southern part of Kurdistan are the Kurdamir and the nearby Topkhana accumulation (Figure 11). The Kurdamir-1 Well tested hydrocarbons from the Oligocene, Eocene and Cretaceous, the former considered to be the most significant volumetrically (Western Zagros Resources, 2015a). The Oligocene Kirkuk Group forms the main productive interval in the Baba and Avanah domes of the Kirkuk Field. Oligocene reservoirs in the Kirkuk Field are interpreted to have been deposited in basinal, back-reef and fore-reef environments with the latter having porosities above 20% and permeabilities up to 1,000 mD. A comprehensive description of these reservoirs is given in Chapter 8 of Aqrawi et al. (2010).
Whilst it is difficult to determine the split of hydrocarbon resources by stratigraphic interval due to paucity of published information, we estimate that the Cenozoic, Cretaceous and Jurassic reservoirs each hold around 30% of discovered resources with the Triassic perhaps 10% (Figure 13).
As more companies start to appraise and develop their discoveries, better estimates will undoubtedly be made. Moreover, with continued deeper drilling it is probable that the volumes of discovered Triassic hydrocarbons will increase over time. Thus far most of the produced oil in Kurdistan has come from the Cretaceous reservoirs in the Taq Taq and Tawke fields.
Recognising and adequately assessing potential hydrocarbon reservoirs in Kurdistan has proven to be challenging. In the northern part of the region, most of the Cretaceous and Jurassic reservoirs are normally or near normally pressured. The combination of low pressure and intense fracturing of the brittle carbonates frequently leads to severe losses whilst drilling. This is particularly true for sections drilled above and close to the water table, the location of which can be difficult to ascertain whilst drilling.
Given the complexity of the subsurface stratigraphy in Kurdistan, logging programs are often extensive by world standards. Logging-whilst-drilling (LWD, mainly gamma-ray and resistivity logs) are very helpful for correlation, especially in the absence of cuttings. In addition to the ‘basic’ wireline log suite, which might include gamma-ray, caliper, resistivity, density, neutron and sonic, specialist logs aimed at better understanding the varying carbonate mineralogy are frequently used. These often include a spectral gamma-ray, neutron-based spectroscopy tools for better determining lithology and clay content and magnetic resonance tools, which can be used to help better evaluate fluid fill and porosity type. Despite extensive log suites it can still be difficult to estimate net pay and moveable hydrocarbons in what are generally low matrix permeability and low-porosity reservoirs.
Conventional coring has proven to be quite variable in terms of recovery and highly dependent on degree of fracturing. Wireline sidewall core tools (mechanical as opposed to explosive) are often used to collect rock samples and are especially useful where cuttings returns to surface have been lacking.
Fracture presence, orientation, whether they are open or closed together with the nature of fluid fill, are critical aspects of most logging programs. Specialist imaging logs are frequently run to aid in the location and characterisation of fracture networks. Hydrocarbon shows, together with losses, will frequently determine the location of zones to be drill-stem tested.
More often than not it is the fractured intervals which give the highest deliverability during drill-stem testing and production. Clearly significant losses (and often no or limited cuttings/gas returns) and lost circulation material (LCM) pumped in these zones displacing formation fluids does not aid subsequent formation evaluation. With the majority of logging tools designed to measure matrix rock properties it can be difficult to properly assess the fluid fill in fractures, especially if the near wellbore environment has been flushed. Wireline tools for obtaining pressures and fluid samples have been used across Kurdistan but with mixed results. In many cases it is not possible to obtain good pressure or sample data due to the difficulty of obtaining a good seal with the probe in hard and fractured carbonates (Garland et al., 2010). Some success has been achieved with the use of advanced probes, in particular large surface area probes in (8½ inch) hole without extensive hole washouts.
Whilst the majority of sandstone reservoirs are water-wet, carbonate rocks over time become mixed-wet or oil-wet. This means that oil can adhere to the surface of carbonate rock and it is therefore harder to produce. Most carbonate reservoirs are believed to have mixed wettability or to be oil-wet (Morrow, 1990). It is probable that the water-wet carbonates are generally those with higher porosity with hard, tight, fractured carbonates being more oil-wet (A. Horbury, personal communication).
Knowledge of rock texture and wettability are vital for the static and dynamic description of carbonate reservoirs and might influence the success of short-term well tests. Very often such parameters require special core analysis (SCAL), the results of which could only be forthcoming after a number of months by which time exploration and appraisal wells might have been tested and abandoned.
Given the petrophysical uncertainty that often remains, even after an exploration well has been drilled and logged, almost all exploration wells in Kurdistan have had quite extensive drill-stem test (DST) programmes. Typically operators have undertaken anything between 4 and 10 DSTs across different reservoir intervals. There have been a mixture of open-hole and cased-hole tests; the latter often using external casing packers (ECPs) to locate the test intervals. In the Shaikan Field the operator has undertaken almost 50 DSTs at different intervals. Some of the tests showed extremely high potential flow rates, which is attributed to the well having penetrated natural fracture networks. Other tests were unsuccessful, with low or no flow, due to the bituminous nature of the oil in places, and possibly the failure to connect with a fracture network. In the Sheikh Adi discovery, two wells have been drilled and a total of 17 DSTs undertaken. Of these 5 are deemed to have suffered mechanical failure (Law et al., 2014).
In heavily fractured reservoirs obtaining seals around ECPs can be problematic. Moreover, a combination of the unfavourable mobility ratio between oil and formation water, and the possibility that there might be different fluid contacts between the matrix and the fractures, can lead to some uncertain test results and complex interpretations.
Hydrocarbon Quality and Type
There is a wide variation in hydrocarbon type and quality across Kurdistan. Published oil gravities range from 12° API to over 57° API (English et al., 2015; Table 2) and significant volumes of gas have also been discovered.
A number of significant discoveries contain heavy oil (i.e. that which has a gravity below 22.3° API as defined by the American Petroleum Institute). In the Shaikan Field it is estimated by the operator that around 80% of the fields estimated hydrocarbon resources reside in Jurassic reservoirs which contain heavy oil with the gravity ranging from 12° to 22° API (Gulf Keystone, 2013). The Barda Rash Field is estimated to have total stock tank oil initially in place (STOIIP) (mid case) in excess of 10 billion barrels of which just over 50% is deemed to reside in Cretaceous reservoirs, which are considered to contain heavy oil (Afren, 2011). The primary reason for oils in the recent Kurdish discoveries being heavy is interpreted to be due to maturity of the source rock; in particular lower maturity oils occurring over the Mosul High and higher maturity oils having been encountered away from this palaeohigh (English et al., 2015). In some cases the heavy oil is considered to be a result of nearsurface meteoric water influx (water washing) and associated biodegradation. It is possible that there is gravity segregation in some of the accumulations which possess significant hydrocarbon columns and one might think that this would result in heavier oils with depth within a particular reservoir but this does not appear to be the case in some fields.
In the Atrush Field (Figure 11), the discovered oil appears to get heavier with depth ranging from 27° API down to 14° API. DST flow rates of up to 16,000 bopd have been achieved but flow rate is critically dependent on reservoir quality, API gravity and viscosity and the lifting mechanism used during the test (Shamaran Petroleum Corporation, 2015a).
In the Shaikan Field, the model that has been applied to the Jurassic in the most recent Competent Person Report (CPR), is that there is moveable oil in the fractures down to a depth of between 1,350 and 1,400 m TVDSS. This is almost 1,000 m below the crest of the Jurassic structure. Below this level is an interval with semi-mobile oil (termed the ‘high viscosity zone’), which extends a further 50–100 m beyond which the fractures are interpreted to be water-bearing. However, the matrix is interpreted to have oil down to 1,950 m TVDSS. There is an interval (1,450 to 1,950 m TVDSS) where water is deemed to be present in fractures surrounding oil-saturated blocks of matrix. The reason for this situation is thought to be due to possible updip leakage of the oil from the structure in recent geological time, causing drainage of the fractures accompanied by influx of water from the aquifer. It is possible that the influx of fresh water caused degradation of the oil to form an interval in the fractures of high viscosity, semi-mobile oil or tar (Law et al., 2014).
Often the heavy oils are associated with hydrogen sulphide (H2S) and carbon dioxide (CO2), which have been known to reach concentrations in excess of 250,000 ppm (25%) and 10%, respectively (Table 1). Whilst drilling the Sangaw North-1 exploration well in 2010–2011, high H2S concentrations were encountered resulting in severe damage to the drill pipe, the well had to be re-drilled.
Where heavy oils have been encountered there have often been difficulties producing them on test. High density, high viscosity and low pressure result in unfavourable mobility and limited flow, unless aided by electronic submersible pumps (ESPs) or nitrogen lift. It is possible that some DSTs have been compromised by water influx from nearby aquifer even though what appear to be ‘good’ oil zones on wireline logs have been perforated. In the Atrush Field, a recent DST in one of the appraisal wells, Atrush-3, flowed 4,900 bopd of 27° API oil using an electrical submersible pump (Shamaran Petroleum Corporation, 2015b).
It has been assumed that thermal recovery techniques would be required to produce heavy oils with recovery from fractures being more significant than from the matrix. Given the volumes of heavy oil in Kurdistan it is very probable that the region will require specialist techniques to recover significant volumes of heavy oil in the future. It is also possible that given the wide range of crude properties in Kurdistan, blending of produced hydrocarbons might facilitate exports.
Leaked and exhumed hydrocarbon accumulations are present at the surface and in near-surface sediments. Here the hydrocarbons appear as either tar, solid bitumen (gilsonite) or in some cases particularly in summer where seeps are active, liquid hydrocarbons (Figure 3). Generally, oil gravities are lower in the near-surface and become higher with depth and stratigraphy, a fact that has been known for many years in Iraqi fields (Dunnington, 1967). Most of the hydrocarbons discovered in Triassic strata have gravities in excess of 36° API and often have a large gas component.
Given that the majority of reservoirs in Kurdistan have low matrix porosity and permeability, fractures are critically important in aiding deliverability, both during testing and production.
There are a number of aspects which must be considered, some of the most important of which are deemed to be fracture porosity, fracture connectivity and fluid contacts (both within the fractures and the matrix). Interference testing has been undertaken on the Atrush Field, between the Atrush-1 and Atrush-2 wells some 2 km apart, and a pressure response was seen “instantaneously” implying a high level of connectivity as a result of the fracture system in this location (Shamaran Petroleum Corporation, 2014). Interference testing between two of the appraisal wells, Chiya Khere-6 and Atrush-2, which are 6.5 km apart, demonstrated pressure communication across the field (Shamaran Petroleum Corporation, 2015b).
In the Shaikan Field, a long-term interference test has been undertaken between Shaikan-IB and Shaikan-3; the wells are around 1 km apart. These data, in combination with conventional well test data, are interpreted to indicate variable flow capacity with the permeability-thickness product over different zones ranging from 12 to nearly 10,000 Darcy-ft. The latter value is extremely high and corresponds to a well productivity index greater than 100 stock tank barrels per day per psi (stb/d/psi). This suggests significant flow contribution of the fracture network.
Estimating recovery efficiency from fractures is not straightforward and will depend, amongst other things on hydrocarbon type, pressure, connectivity, interaction with matrix and aquifer, as well as the recovery mechanism employed during development. In the Taq Taq Field, it has been interpreted that the Shiranish and Kometan formations could be considered to be type 1 fractured reservoirs, in which both storage and deliverability are provided only by the fractures. The underlying Qamchuqa Formation, however, has been treated as a type 2 fractured reservoir, in which storage is provided by the matrix and deliverability is provided by the fractures (Garland et al., 2010).
An important recovery mechanism in fractured reservoirs in which water moves through the fracture network involves natural imbibition of water into matrix blocks resulting in the expulsion of oil from the matrix blocks into the fractures where the oil is transported to the producing wells.
Within giant Taq Taq Field, the failure of the Taq Taq-5 Well to flow hydrocarbons on test has been interpreted to have been due to the well penetrating an interval with an absence of fracture porosity. The well was located crestally and close to the middle of the field (Vallares, 2011). The Ain Al Safra-1 Well had DSTs in the Butmah and Adaiyah formations which were inconclusive as the tests were unable to connect to a permeable fracture network and flow fluids to surface (Oryx Petroleum, 2013).
EXPLORATION SUCCESS RATES AND FAILURES
Given the quality, distribution and maturity of source rocks in Kurdistan, almost all wells drilled to date have encountered oil and/or gas in some quantities. The measure of exploration success adopted for the purpose of this study is to count the total number of new field wildcat wells and classify them as having been successful or having failed based on them flowing hydrocarbons (500 bopd or over) to surface. Where initial new field wildcat wells have failed to flow, but sidetracks have proven successful then these are counted as successful exploration wells. Using this approach some 63 new field wildcat (NFW) wells have been drilled and tested in Kurdistan between 1901 and late 2014. Of these 23 are regarded as unsuccessful wells and 40 as successful giving a NFW success rate of 63%. Clearly different workers could well view the same data in a different light. The vast majority of these data are in the public domain and where data has not been published, scout information (maps, industry articles and public reports) have been used.
Of the 63 new field wildcat wells, 25 are deemed to have been drilled beyond the mountain front and 38 to the west and southwest of the mountain front on the ‘plains’. Of the 25 wells drilled in the more mountainous terrain, 12 of these are deemed to have been successful and 13 have failed giving a success rate of 48%. There are 38 wells that are considered to have been drilled to the west of the mountain front and on the plains. Of these 28 are considered to have been successful giving a success rate of 70% in this region. Success rates appear to be lower in the more mountainous areas, presumably as a result of trap destruction and seal breaching.
It is difficult to accurately estimate commercial success rates as a large number of the discoveries are still under appraisal or field development plans and economics are unknown. However, almost a third of the discoveries have had field development planning approval and in all probability more commercial discoveries will follow post-appraisal (Figure 11).
Of the 40 successful new field wildcat wells, 12 have matured into commercial fields with approved field development plans (Figure 11, Table 2). Eight of these are on the plain and 4 in more mountainous terrain. Of the remaining NFW discoveries it is very likely that the majority of them will be commercially viable; some are presently producing at low rates to the local market. This is likely to change as additional export pipeline infrastructure becomes available. Moreover, as such infrastructure develops, the economic viability of tie-backs and accumulations with smaller reserve sizes should become more favourable.
In some cases the initial new field wildcat wells have encountered hydrocarbons but have failed to flow on test. One such example is the Qara Dagh-1 Well, which was drilled by Vast Exploration in 2010 (Figures 8 and 11). The well encountered approximately 1,000 m gross oil column of 41° API oil in the Tanjero and Shiranish formations but was deemed, post-drilling, to have been drilled sub-optimally on a steep flank of the structure. A second well was planned but not drilled (Vast Exploration, 2011) and the company relinquished the acreage back to the KRG in late 2012. Within 6 months Chevron Corporation had signed the block (Chevron, 2013) and are believed to be planning a second well on the block along trend from the historic well (Western Zagros Resources, 2014a).
Whilst Kurdistan has seen high success rates, and almost every well has encountered some traces of hydrocarbons, there have been a number of ‘dry’ holes drilled in the last 10 years; wells where the operator has deemed that the structure drilled is devoid of commercial hydrocarbons (Figure 11).
The exploration wells, which are considered to have “failed”, are spread across the region and present both in the fold belt and on the plains to the southwest. There is no apparent structural trend to their distribution. These “failures”, in our opinion, can broadly be grouped into 5 categories:
(1) well drilled in wrong location on a structure, off the crest or out of closure, through a thrust or in an isolated compartment;
(2) missed pay, or inadequate testing and/or formation damage, or failure to connect with a permeable fracture network;
(3) not drilled deep enough to adequately test all the reservoir units that might be in closure; e.g. heavy oil encountered in the Cretaceous but deeper targets in the Jurassic and Triassic untested;
(4) lack of hydrocarbon charge into the structure as a result of either: (i) compromised migration route (e.g. sealing by major thrust or shear fault, or that the structure is in a migration shadow); or (ii) timing of structuration with respect to hydrocarbon migration (i.e. very young or exhumed structure too recent to receive hydrocarbon charge);
(5) structure and top seals breached resulting in seal and thus trap failure and leakage.
The first three points are arguably failures in adequately drilling in the optimal location or adequately evaluating the well, and might not necessarily condemn the particular structure in question. Whilst such wells have been classed as failures it is possible, and indeed has been proven in some instances, that additional drilling and testing has resulted in successful wells on structures that others have drilled and abandoned. It is worth noting that a number of structures in the main part of Iraq, such as Ain Zalah and Butmah (Figure 1), have only very limited production over much of these structures. Single well penetrations can be unrepresentative of these big structural anticlines. Almost all new field wildcat wells have been drilled on relatively sparsely spaced 2-D seismic data and the assumption has generally been that the structures are large anticlines that can be tested with a single, generally crestal, exploration well. In a fold-and-thrust belt setting this is almost certainly an over simplification.
In our opinion there are very few exploration well failures due to inadequate or absence of suitable reservoir facies. However, almost all carbonate reservoirs in Kurdistan have low matrix porosity and permeability and are usually dependent on fracturing to yield commercial flow rates. In some cases reservoirs have been encountered, with hydrocarbons, but lack of open fractures have resulted in “failure” of the well to flow hydrocarbons at adequate flow rates. This is interpreted to have occurred in Ain Al Safra-1 and also in the recent Demir Dagh-5 appraisal well where two DSTs in the Cretaceous flowed small quantities of oil to surface but were unable to re-connect with the permeable fracture network (Oryx Petroleum, 2013; 2014b). Moreover, almost all exploration wells have been vertical and it is probable that this is not the optimum orientation to intersect fractures within the reservoir. Two recent appraisal wells on the Bijell Field (Bijell-4 and Bijell-6) failed to encounter movable hydrocarbons. Assuming these wells were drilled within the field closure then presumably these results were either due to the low mobility of the reservoir fluids or a lack of fracturing of the reservoir at these locations, or a combination of the two factors (MOL, 2015).
Excellent source rocks are also present in the subsurface in most of Kurdistan; however adequate maturation and migration are of greater risk and uncertainty. With almost all exploration wells being crestal, the extent, thickness, quality and depth of potential source rocks in the synclinal areas is uncertain. It is probable that most migration is relatively recent (post-structuration) and as such is probably quite local given the difficulty of migrating hydrocarbons over large distances. Fill-and-spill between accumulations may exist but is yet to be proven. The extent and depth of source kitchens is a more regional issue related to basin evolution and petroleum systems. Thus far operators in Kurdistan have operated on their own acreage with limited working interest in other blocks. With no formal release period for well and seismic data in Kurdistan, there are no comprehensive regional basin modelling studies, which utilise the abundance of well and seismic data, which has been acquired over the last 10 years. This is perhaps one of the most important aspects of petroleum systems evaluation in Kurdistan that remains to be understood. A regional basin model showing the lateral variations in source rock quality, thickness, heat flow, and detailed timing of structuration from the foreland through the fold belt would undoubtedly permit a better understanding of the timing of maturation and migration from both local and more regional source kitchens. Such a study would benefit from a comprehensive standardisation of stratigraphic nomenclature, to ensure consistency across the entire region.
If tectonic uplift were the sole cause of trap destruction then there would not have been significant hydrocarbon discoveries such as Shaikan, Atrush, Swara Tika, Bina Bawi and Miran beyond the mountain front. However, of the successful exploration wells drilled in Kurdistan, it is estimated that around 70% of them reside on the Cenozoic-covered plains with only 30% in the mountainous areas. In the more mountainous areas where Cenozoic strata are absent, traps are reliant on the sealing capabilities of shales and anhydrites, in particular within the Jurassic and Triassic sequences.
It is possible that the sealing capacity of such strata could be compromised by uplift and tectonic fracturing coupled with cooling and depressuring. Two examples are presented which highlight some of the complexities encountered to date.
Example 1: Harir Anticline and Mirawa Structure
In the northern part of Kurdistan the prominent Harir Anticline rises about 700 m from the surrounding plains. In 2013 an exploration well (Harir-1) was drilled close to the crest of this structure penetrating Cretaceous, Jurassic and Triassic strata (Figures 11 and 17). The well was tested and deemed to be dry (Marathon Oil Corporation, 2013a, b, c). Soon after another exploration well was drilled less than 12 km to the southwest on a low-relief structure on the plain below. The Mirawa-1 Well also penetrated Cretaceous to Triassic strata and flowed high-quality oil from the Jurassic, and gas with condensate from Triassic strata (Marathon Oil Corporation, 2013a, b, c). Both structures are likely to contain very similar reservoir facies and both appear to be prominent anticlines, albeit that the Mirawa structure is more deeply buried compared to the Harir Anticline. Assuming that both wells were valid tests of the structures, the possible reasons for failure of the Harir-1 Well are considered (by the authors) to be as follows:
(1) it is cut off from the source kitchen to the south by the reverse fault interpreted along its southwestern limb;
(2) the structure has been breached, seals are ineffective and migrated hydrocarbons have leaked away;
(3) the structure is too young to receive hydrocarbons;
(4) the well was drilled in a faulted compartment within the large structure which is somehow isolated from charge;
(5) the well might have been drilled outside of structural closure at the depth where reservoir targets were encountered.
There are no known seeps on the Harir Mountain, which might preclude significant leakage from the Harir structure. If however, the escaped hydrocarbons were light oil and/or gas then it is possible that all traces have disappeared. In many areas hydrocarbon maturation and migration appear to be very recent and occurring present-day. Although the structure is undoubtedly young, is it too young to receive hydrocarbons that may well be migrating present-day? Seismic over the Taq Taq Field clearly shows folding of the Bakhtiari and Upper Fars Pliocene sediments implying very recent hydrocarbon migration into this structure. The authors favour either the first or second hypotheses as to why the large Harir structure is dry, although it is theoretically possible on such a large structure (25 km in length and up to 5 km in width) that the well might have been drilled into an isolated compartment or in a region lacking significant faults.
Example 2: Sangaw Anticline
The second example is from the southern part of Kurdistan where the Sangaw North-1 exploration well was drilled on the northern part of the large Sangaw Anticline (Figures 11 and 18). The well penetrated Cenozoic to Triassic sediments but flowed non-commercial gas and water at rates of 4.6 million standard cubic feet of gas and 7,280 barrels of water per day (Sterling Energy, 2011b, 2012). The Sangaw North block has since been relinquished by the operator. Less than 15 km to the south are the Topkhana and Kurdamir discoveries with oil, gas and condensate having been tested from Cenozoic and Cretaceous reservoirs.
Unlike the northern part of Kurdistan, thick Cenozoic strata occur in this region and the presence of evaporite and shale facies are considered to have facilitated shallow, low-angle thrusting. Whilst the cross section interprets lateral facies pinchout of Cenozoic reservoirs, there are a number of significant thrusts and thrust sheets, which potentially separate the downdip discoveries from the updip ‘dry hole’. It would appear that the Sangaw North-1 Well drilled a valid structure with adequate fractured reservoirs; however, hydrocarbons have either been unable to migrate into the structure in any significant quantities, or they have migrated and leaked away due to seal failure as a result of more recent tectonism. Some hydrocarbons seeps have been seen over the Sangaw Anticline and it is thought most likely that this large structure was dry as a result of seal failure and breaching of the trap.
PRODUCTION AND RESOURCES
Whilst presently there are 12 discoveries with approved field development plans (Figure 11), four fields have dominated production history in Kurdistan to date: Taq Taq, Tawke, Khurmala and Kor Mor. Since 2008, these fields have together produced over 400 million barrels of oil equivalent (MMBOE, Table 3). In 2012, the Taq Taq Field produced 27.5 million barrels of oil (MMBO) averaging 75,500 barrels of oil per day (bopd; Genel Energy, 2013). In 2013 production averaged 77,000 bopd (28.1 MMBO) and in 2014 production had increased to an average of 103,000 bopd (37.5 MMBO) (Genel Energy, 2015). In total the Taq Taq Field is estimated to have produced in excess of 138 MMBO.
The Tawke Field produced a gross average of 45,477 bopd in 2012 (16.5 MMBO) whilst in 2014 average production was 91,000 bopd (33 MMBO) (Genel Energy, 2015). The field has produced over of 100 MMBO to date (DNO, 2015). The Kor Mor Field has produced almost 90 MMBOE, comprising 415 billion cubic feet (bcf) of gas and 18 MMBO of condensate since 2008 (Dana Gas, 2013). The Shaikan, Barada Rash and Sarqala fields have together produced around 9 MMBO, but these fields are not yet connected to pipeline infrastructure, limiting production to export via truck at the present time.
Some of this production has been consumed by the local market, whilst some has been exported. As of early 2015 additional pipeline capacity has now been constructed, production from the region has been increasing over the last 24 months and is likely to increase in the future.
Oil-in-Place, Reserves and Recovery Efficiency
Published numbers for oil-in-place, reserves and recovery factors for fields and discoveries in Kurdistan are difficult to come by. Whilst the publically listed operators of the producing Tawke and Taq Taq fields regularly publish reserve estimates, accurate numbers for many of the other discoveries are somewhat harder to come by and often restricted to infrequently updated CPRs. In part this is due to the difficulty in estimating recovery factors and thus moving from in-place figures to recoverable hydrocarbons for discoveries, which have not been fully appraised.
Estimating oil-in-place relies on an understanding of matrix parameters such as gross rock volume, porosity, net-to-gross and hydrocarbon saturation. In carbonate reservoirs in Kurdistan these parameters can be difficult to measure and extrapolate across large structural features. Measuring similar parameters for fractures can be even more difficult.
Within carbonate reservoirs in Kurdistan a number of fracture types have been recognised. These range from seismically visible tectonic fractures to microfractures associated with stylolites. In the more mountainous areas a large number of the fractures are associated with strongly folded and at times thrusted anticlines. Published data on fractured carbonate reservoirs in strongly folded anticlines in Iran suggested a range of fracture porosity from 0.1–0.3%. These estimates were derived from material balance calculations (Weber and Bakker, 1981). Within Kurdistan published estimates of fracture porosity for various fields and discoveries are presented in Table 4.
In theory, if the matrix porosity, fluid compressibility and the tidal attenuation ratio (reservoir tidal and surface tidal amplitudes) are known, there is a chance that fracture porosity can be estimated. This is only possible if the matrix porosity is low, fluid compressibility is low and the fracture system is not parallel to the overburden stress (L. Kaye, personal communication).
In the Cretaceous of the Taq Taq Field, the operator estimates fracture porosity to be 0.3% and the permeability of the fracture network to be several Darcies to infinite. These estimates are made on the basis of wireline log, core, well test inflow, pressure data and mud losses. Productivities show a considerable range from a 4 bbl/day/psi up to 500 bbl/day/psi. In the Shaikan Field, interpretation of DST data indicates highly variable productivities from 4 to 148 bbl/day/psi with test permeabilities ranging from 180 to 14,700 mD (Law et al., 2014, their table 5.8).
Clearly, if a pervasive connected fracture network is present (and proven with inflow/production test data), then recovery efficiency from this fracture network could be significant; perhaps 60–80%.
Recovery efficiency from matrix systems with more limited fracture networks are much lower. It is difficult to generalise as there are many factors which influence recovery factor such as formation pressure, fluid type, viscosity, wettability of the matrix system, capillary pressure, wellbore contact (horizontal versus vertical production wells), skin damage, aquifer support, development well spacing and number, and depletion strategy. In the Taq Taq Field the operator has suggested a recovery factor of between 30% and 50% for the Cretaceous reservoirs (Addax Petroleum, 2009).
Given the wide variations in hydrocarbon type and reservoir properties most operators have taken the approach of calculating separate recovery factors for the matrix and the fractures in each reservoir unit. In the Shaikan Field this has resulted in there being a wide variation in recovery efficiency between the low viscosity oil in the matrix in the Cretaceous (0% recovery assigned) and the higher pressure, light oil in fractures within the Triassic (up to 80% recovery efficiency) (Table 5; Law et al., 2014). This range is perhaps typical for other accumulations in the region.
Published reserve estimates suggest that there have been 8 discoveries in Kurdistan with 2P (proven and probable reserves) and 2C (best estimate of contingent resources) in excess of 500 million barrels (Figure 19a). The total 2P reserves and 2C resources discovered to date are estimated to be in excess of 15 billion barrels of oil (based on published numbers).
With limited fields in Kurdistan having been fully appraised or in production for any length of time, it is only possible to draw upon publically released data from the Tawke and Taq Taq fields as a guide to field performance and how reserve estimates have changed over time. Between them, these fields have had 43 wells drilled, of which 40 are presently in production and these two fields have produced in excess of 230 MMBO to date.
When the Tawke-1 Well was drilled and successfully tested in 2006 the operator (DNO) estimated that the field had 100 MMBO recoverable reserves in Cenozoic carbonates. Hydrocarbons were encountered in deeper Cretaceous reservoirs but as these were untested no reserves were ascribed to them at that time. Between 2006 and 2014, a total of 28 wells have been drilled on the Tawke Field (DNO, 2014). These wells not only appraised different parts of the field, but also explored deeper targets adding new reserves. Moreover, extended well testing permitted the use of down-hole gauges which were used for evaluating pressure communication across the field and between production and injection wells.
Figure 19b shows the published reserve figures for the Tawke Field from its initial discovery in 2006 to present-day. In 2013, following the drilling of a second horizontal well and the discovery of additional reserves in the Jurassic Sargelu Formation, DNO suggested that the recoverable reserves could be “bumped up to the 1 billion barrel mark, compared with the present level of 771 million barrels” (DNO, 2013b). Moreover, field enhancements are being considered to increase the daily output from 100,000 bopd to over 200,000 bopd (Figure 19b), from an initial facility that was scoped for just 50,000 bopd. Over the last 7 years these reserve additions have largely come through recognising reserves in additional reservoir units and by greater recovery from the field’s existing reservoirs based on production data and significant encouragement from recent horizontal wells. In October 2013, the Tawke-23 Well flowed at a rate of 32,000 bopd from a 900 m horizontal section in the Cretaceous and was drilled at a cost of just US $12 million. The most recent horizontal well, Tawke-27, was drilled in record time and at a cost of under USD 10 million (DNO, 2014). Clearly the commercial viability of such wells are helped by what appear to be very efficient and cost-effective appraisal and development drilling. In 2014, the operator drilled 5 horizontal production wells bringing the total number of horizontal producers to 9 out of a total of 26 production wells (DNO, 2014; Genel Energy, 2015).
In 2007, 2P gross reserves in the Taq Taq Field were estimated to be ca. 210 MMBO. By 2008 this estimate had increased to 304 MMBO and current field remaining reserves (2P) are estimated to be 579 MMBO (Genel Energy, 2015). The first horizontal well was planned for late 2014 (Genel Energy, 2014c).
Not all discoveries in Kurdistan have grown over time. In 2012 a CPR was published on the Barda Rash Field, which estimated that the accumulation had 2P reserves of 190 MMBO and 2C resources of 1,243 MMBO making it one of the largest new finds in Kurdistan (Afren, 2012a). In January 2015, the operator announced that the results of an updated CPR had reduced the 2P reserves to zero and the 2C resources to around 250 MMBO (Afren, 2015). The significant reduction in 2P and 2C reserves and resources has been due to the 2014 reprocessing of 3-D seismic acquired in 2012 and initially processed in 2013, alongside the companies drilling campaign. Overall the reservoirs have not performed according to previous expectations and what was assumed in the approved Field Development Plan (FDP). The wells have produced higher water cuts than expected and the operator encountered operational challenges associated with the drilling of difficult complex fractured reservoirs. Whilst recent results at the field have indicated the presence of light oil accumulations in the Triassic Kurra Chine reservoirs, these have high levels of associated H2S, which might require significant capital to develop (Afren, 2015).
Horizontal Wells and 3-D Seismic
Many carbonate reservoirs in Kurdistan have low matrix porosity and low matrix permeability. At times these reservoirs are highly fractured resulting in improved productivity. In such settings, horizontal wells are often effective at intersecting high-angle fracture systems and in maximising flow rates whilst minimising pressure draw-down. Horizontal wells have been used extensively in carbonate reservoirs around the world, especially so since the advent of reliable 3-D seismic data in the 1990s.
To date there have been just 10 horizontal wells in Kurdistan, nine in the Tawke Field and one in the Bastora Field. These wells have all been planned and drilled on 3-D seismic data. Two of the horizontal wells completed in the Tawke Field, Tawke-20 and Tawke-23, were brought on-stream during 2013 at rates of 25,000 bopd and 32,500 bopd respectively, some of the highest flow rates in Kurdistan to-date (Genel Energy, 2014c). Two additional wells, Tawke-21 and Tawke-22 were brought on stream in 2014 and production was initiated at a combined rate of 37,000 bopd. In one of the new wells, Tawke-21, eight productive fracture corridors penetrated by a 980-metre horizontal section in the main Cretaceous reservoir interval flowed an average rate of 9,700 bopd each. In the other well, Tawke-22, located six km away, seven productive fracture corridors penetrated by an 800-metre horizontal section flowed an average rate of 8,800 bopd each. Both wells are subject to wellbore and surface facilities limitations (Genel Energy, 2015). A further five horizontal wells were drilled in 2014 (DNO, 2014).
The Bastora-1 Well is significant due to the flow rates achieved from the horizontal well. Although less than 2,000 bopd, the rates were four times higher than those achieved from the vertical well in the same reservoir interval (DNO, 2012b). The first horizontal well was planned for the Taq Taq Field in 2014 (Genel Energy, 2014c) and high-angle wells have been drilled on the Miran and Benenan fields.
Horizontal drilling is relatively new to Kurdistan, largely due to the fact that there are few appraised fields with 3-D seismic data over them. However, the results of these early wells are very encouraging. As more 3-D seismic surveys are acquired, and more advanced processing (such as pre-stack depth migration and seismic inversion) are undertaken, it is likely that many more horizontal and highangle wells will be drilled potentially commercialising low-porosity/permeability reservoirs that might otherwise remain unexploited.
FUTURE TRENDS IN KURDISTAN
The transformation of Kurdistan into a new and significant oil region over the last decade has been remarkable. The time line of events shows some of the key milestones that have been achieved in the last decade (Table 6). It is highly probable that technical and commercial success rates will remain high whilst four-way dip closures are still available for new field wildcat drilling. More 3-D seismic surveys will be acquired and these will no doubt reveal additional complexities which 2-D seismic is unable to illuminate. It is possible that 3-D seismic, in certain conditions, could identify areas of possible better reservoir development and perhaps even hydrocarbons.
Horizontal and multilateral wells are likely to be essential in the development of many fields and multilateral drilling and fracture proping may prove cost effective in some instances. As fields are developed, water injection may well be required to sustain and enhance production levels and recovery efficiency as has happened in other carbonate provinces. This may place a strain on water resources. A number of accumulations have discovered large volumes of heavy oil (API < 20°) and these are likely to require the use of enhanced oil recovery methods such as thermal or solvent techniques to facilitate commercial recovery. High levels of hydrogen sulphide gas will necessitate the use of specialist processing facilities, such as amine gas treatment, to remove or significantly reduce H2S and in some cases CO2 concentrations.
As more fields come into full production, the understanding of the dynamic behaviour of the reservoirs will improve dramatically. Given the number and variety of carbonate reservoirs in the region it is very probable that stratigraphically trapped hydrocarbons will continue to be discovered. Pure stratigraphic traps are unlikely to be significant targets until dip and fault closed structures are all drilled out.
The industry has been surprised by the discovery of the hydrocarbon reservoirs in ever yet deeper stratigraphy. The Triassic is proving to be an important contributor to the reserve base in Kurdistan, not least because the hydrocarbons that have been discovered are generally lighter (higher API, higher GOR and more mobile) and of higher pressure than shallower discoveries. It is very probable that hydrocarbons will continue to be discovered in older Triassic strata and probably within the Permian and perhaps even within Carboniferous strata although very few wells have thus far targeted levels below the Upper Triassic. Given the wide variety of hydrocarbon qualities discovered in the region, it is probable that there would be benefit in blending crudes, which might facilitate higher overall exports from the region.
There is an increasing need for a regional and industry-wide understanding of petroleum systems and seal efficiency in Kurdistan. Significant unknowns include the timing of generation versus trap formation, the importance of vertical migration and especially seal efficiency, the role of thrusts and strike-slip faults in migration efficiency. Kurdistan does not have a public release mechanism for data although in-country operators are increasingly able to trade data, with the approval and facilitation of the MNR. This should lead to improvements in exploration efficiency and a better understanding of drilling practices, stratigraphy, facies variations and petroleum systems in the region.
For almost a decade, our colleagues Tarik Chalabi, George Yaku and Azad Tahir Saeed have provided invaluable guidance on Iraqi geology, field locations and thoughts on hydrocarbon prospectivity in northern Iraq. Our ideas have also been shaped by our many colleagues at Petroceltic International and the Ministry of Natural Resources. The authors would specifically like to thank Joseph English, Dermot Corcoran, Ciaran Nolan, Paul Ryan and Sean McDade (Petroceltic), Andrew Horbury (Cambridge Carbonates) and John Bounds (Blueasterisk cartography) for valuable input to the manuscript. We also acknowledge valuable input from the team at GeoArabia including Moujahed Al-Husseini, Nestor “Nino” Buhay IV and Kathy Breining. Cara Burberry’s input is also gratefully appreciated. Thanks also to Petroceltic International and the Ministry of Natural Resources of the Kurdistan Regional Government for their continued support and permission to publish this manuscript.
All reserve figures and well results detailed in this paper are taken from public domain sources and the authors have made best efforts to ensure that these are correct at the time of going to press. The opinions expressed in this paper are those of the authors and do not necessarily represent those of their respective organisations.
ABOUT THE AUTHORS
David Mackertich is an Exploration Geologist who has been working with Petroceltic International since their entry into Kurdistan in 2009. Prior to this he was employed by Gulf Keystone where he led the technical team that helped acquire the company’s interests in the Shaikan and Akri-Bijeel blocks in late 2007. Between 1991 and 2003 he worked for Hess Corporation in the UK, Denmark and Malaysia. David holds an MBA from London Business School, and MSc in Petroleum Geology from University College Dublin, Ireland and is a Fellow of the Geological Society of London.
Adnan Samarrai is a geologist, explorer and a key technical advisor in the Ministry of Natural Resources (MNR) of the Kurdistan Regional Government (KRG), Iraq. Adnan received his BSc degree in Geology in 1962 from the University of Baghdad, Iraq. He commenced work in 1962 with Binnie & Partners later moving to the Iraq Petroleum Company (IPC) and then to the North Oil Company (NOC). Prior to joining the Ministry of Natural Resources, Adnan was Country Manager for Gulf Keystone in Kurdistan where he played a significant role in the capture of the company’s acreage in the country and the discovery of the Shaikan Field. Adnan is an Emeritus Member of the AAPG and Fellow of the Geological Society of London.