Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization.
The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations.
This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans.
The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations.
The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
The North Kuwait Jurassic Gas (NKJG) reservoirs are currently under development by KOC with assistance from Shell under an Enhanced Technical Services Agreement (ETSA). The fractured carbonate reservoirs contain gas condensate and volatile oil at pressures up to 11,500 psi with 2.5% H2S and 1.5% CO2. This paper describes the planning and implementation of a Well Integrity Management System (WIMS) that allows the safe management of the wells that are being drilled in this hazardous environment.
The wells are designed and constructed in accordance with KOC standards and on transfer of ownership from Deep Drilling Group to Production Services Group have their integrity managed under WIMS. The system is a structured process, relating the frequency and extent of routine monitoring and testing to the particular risks associated with the wells. Compliance with WIMS requirements are routinely reported so that all are aware of the current state of well integrity. WIMS is initially managed through simple spreadsheets and during 2012 is being integrated into KOC's Digital Field infrastructure.
Initially, WIMS has been applied to the range of wells ‘owned' by Production Services Group and tests currently carried out by Well Surveillance Group under PSG's direction. In order to realise the full assurance of safe operation the scope of WIMS application is being extended to the full well population, including suspended wells, and the full range of tests required.
Implementation of WIMS will allow KOC (NKJG) to be able to state that ‘our wells are safe and we know it'.
Carbonate formations are very complex in their pore structure and exhibit a wide variety of pore classes. Pore classes such as interparticle porosity, moldic porosity, vuggy porosity, intercrystalline porosity, and microporosity. Understanding the role of pore class on the performance of emulsified acid treatment and characterizing the physics of the flow inside is the objective of our study.
The study was performed using vuggy dolomite cores that represent mainly the vuggy porosity dominated structure, while the homogenous cores represent the intercrystalline pore structure. Core flood runs were conducted on 6 x 1.5 in. cores using emulsified acid formulated at 1 vol% emulsifier and 0.7 acid volume fraction. The objective of this set of experiments is to determine the acid pore volume to breakthrough for each carbonate pore class at different injection rates.
In this paper, a novel approach to interpret the core flood run results using thin section observations, tracer experiments, SEM, and resistivity measurements will be presented. Thin section observations provide means to study the vugs size and their distribution, connectivity, and explain the contribution of the pore class in the acid propagation. Relating the rotating disk experiments of emulsified acid with dolomite to our core flood run results will be also conducted in order.
The acid pore volumes to breakthrough for vuggy porosity dominated rocks were observed to be much lower than that for homogenous carbonates (intercrystalline pore structure). Also, the wormhole dissolution pattern was found to be significantly different in vuggy rocks than that in homogenous ones. Comparison of thin section observations, tracer results and the core flood runs results indicates that the vugs are distributed in a manner that creates a preferential flow path which can cause a rapid acid breakthrough and effective wormholing than those with a uniform pore structure. Rotating disk experiment results, demonstrating that the reaction of emulsified acid with dolomite is much lower than that with calcite, showed that the reaction kinetics played a role in determining the wormhole pattern.
The demand for hydrocarbons is expected to grow worldwide. As a result, deeper reservoirs are being explored. Emulsified acid systems are preferred for the stimulation of high-temperature carbonate reservoirs with bottomhole temperatures (BHTs) of 275°F and above. The retarded nature of an emulsified acid system decreases both the acid reaction rate and the rate of corrosion. However, the lack of emulsion stability of these systems is a major problem associated with high-temperature applications (at 300°F and above).
Corrosion inhibitors and intensifiers can interfere with the stability of an emulsified acid system, which consequently leads to higher corrosion losses. At the same time, there is a need for better inhibition systems to counteract the effects of corrosion at higher temperatures. In this paper, a combination of three intensifiers was used, based on the differences in their mechanisms for inhibitor intensification action. The study includes the effect of varying the concentration of each component, hydrochloric (HCl) acid strength (20 to 28%), and temperature (275 to 325°F) on the stability and corrosion rate using P-110/N-80 coupons. The unique combination of the corrosion inhibitor and three intensifiers with proper optimization created a system capable of passing a corrosion test at 300°F using 28% HCl acid. The temperature limit of the system can be extended up to 325°F using an additional intensifier with 25% acid strength.
The present system can be used for acid stimulation of carbonate reservoirs with BHTs up to 325°F. This study revealed a better understanding of the effect of the intensifiers in an emulsified acid system and the synergism amongst them. This enabled the use of an emulsified acid stimulation on carbonate reservoirs having BHTs up to 325°F while reducing the corrosion rate to a level that meets the current market demand for acidizing operations. This work shows that emulsified acid systems can be used with HCl acid strengths ranging from 20 to 28% at high temperatures. The resultant better wormholing at high temperatures should also lead to enhanced oil production.
Influenced by the success of shale gas production worldwide and to meet requirements for clean energy supply, a multidisciplinary team of petroleum specialists was established in Saudi Aramco. Meeting the growing requirement in industrial consumption and especially electricity production is driving force for developing unconventional gas reserves. "The initial focus is in the northwest and in the area of Ghawar, where gas infrastructure exists. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2011. The company is innovatively combining knowledge and research to maximize gas reserves and production from conventional and unconventional resources in order to meet growing domestic demand.?? 
During years 2010 - 2011 major international petroleum industry players - Schlumberger, Halliburton and Baker Hughes - were invited to share their experience in a series of workshops held in Dhahran. Exchange of expert ideas developed into appreciation of complexity of the shale gas reservoir and helped to identify the scope of work for the first Silurian Qusaiba shale gas well. The SHALE-1 well was drilled in 2007 as a gas exploration well. Recent drilling and geophysical data obtained in the well were beneficial for detailed sidetrack and fracture stimulation design.
The Multidisciplinary Saudi Aramco - Halliburton SHALE-1 task group was established and positioned in Dhahran. This allowed them to have regular face-to-face meetings and improve the most critical criteria of any new venture - communication. The draft work plan was developed 8 months before actual operations commenced on the well site. Thorough examination of the draft work plan progressed to the final work plan with a number of improvements. For example, "R?? Nipples were dropped from the monobore 4-1/2?? completion string. The Frac Stimulation design was fine-tuned, involving expertise from Saudi Aramco and Halliburton. The Complete Well on Paper exercise involved over 25 specialists from both sides and helped to rectify remaining completion/stimulation design issues, and put everyone on the same page in terms of the work program. Well site operations commenced in May 2011; the well was successfully re-entered and window cut in 7?? liner. An S-shaped 5-7/8?? hole was drilled in the direction of minimum horizontal stresses, to the required depth in Qusaiba Shale with a maximum DLS of 4°. The well was completed with 4-1/2?? cemented liner and monobore 4-1/2?? string to surface. The Hot Qusaiba interval was perforated; frac stimulated with mixed results and successfully flowed. A temporary isolation FasDrill plug was set above the perforation interval. The Warm Qusaiba interval was perforated; successfully frac stimulated and flowed with mixed results. Finally, the FasDrill plug was drilled out with CTU and both intervals flowed and required production log runs.
All targets set for the SHALE-1 re-entry well were successfully achieved and the well was suspended for future utilization as an observation well.
Three significant source rocks are present beneath much of the Alaska NorthSlope (Fig. 1), the Triassic Shublik Formation, the lower part of theJurassic-Lower Cretaceous Kingak Shale, and the "Brookian shale" that includesthe Cretaceous pebble shale unit and Cretaceous-Lower Tertiary Hue Shale.Although these source rocks are known to have generated oil and gas thatmigrated into conventional accumulations, including the super-giant Prudhoe Bayfield, the first attempt to produce hydrocarbons directly from the three sourcerocks was initiated in 2012.
The Shublik Formation contains a mixture of Type I and IIS kerogen, and oilin conventional accumulations sourced from the Shublik is of relatively lowgravity (23-39° API) and high sulfur (more than 1.5 percent). In contrast, theKingak and Brookian source rocks contain a mixture of Type II and III kerogen,and oil in conventional accumulations sourced from those rocks is of relativelyhigh gravity (35-42° API) and low sulfur (less than 0.3 percent). These threesource rocks occur at depths that range from less than 3,000 feet along theBarrow Arch to more than 20,000 feet in the Brooks Range foothills. Over thatrange of depth, thermal maturity of the source rocks grades from the onset ofoil generation along the Barrow Arch, through the oil window, and well into thedry gas window in the south (Fig. 1).
Shale-oil and shale-gas assessment units (AUs) - areas where organic richfacies are inferred to be in the oil or gas window, respectively - weredelineated for each source rock (Figs. 2, 3, 4) based on empirical thermalmaturity data and regional modeling (Houseknecht et al., 2012a). Both Shublikand Brookian source rocks include rock types that are brittle and in whichnatural fractures are common. Brittle lithologies include limestone, phosphaticlimestone, sandstone, siltstone, and chert in the Shublik and very-fine-grainedsandstone, siltstone, concretionary carbonate, and silicified tuff in theBrookian. In contrast, the Kingak source rock is mostly clay shale that deformsplastically, and brittle lithologies generally are absent. These petroleumsystem elements (organic matter content, thermal maturity, and brittlelithology) were among the factors considered in estimating the probability thatoil and gas can be technically recovered from the source rocks, with results of95 percent probability for the Shublik, 90 percent for the Brookian, and 40percent for the Kingak (Houseknecht et al., 2012b).
Maps of petroleum system elements were used to evaluate spatial variabilityin source rock character. A map of mostly transgressive facies in the ShublikFormation (Fig. 2) delineates areas that may contain highest organic content,based on published relations between transgressive facies and total organiccarbon (TOC) in the formation (Hulm, 1999; Robison and Dawson, 2001; Peters etal., 2006; Kelly et al., 2007). The Shublik is absent owing to non-depositionat Pt. Barrow and transgressive facies in the formation thicken basinward in aradial pattern, reaching maximum values greater than 200 ft in northeastern andwestern NPRA (Fig. 2). East of NPRA, the Shublik thins depositionally towardsPrudhoe Bay, and is truncated completely farther east beneath the LowerCretaceous unconformity (Fig. 2). In northcentral NPRA, Shublik transgressivefacies are not only relatively thin (less than 100 ft) but also containgenerally low organic carbon content (Fig. 2) and low values of interpretedoriginal hydrogen index (Peters et al., 2006). Both the TOC content (Fig. 2)and interpreted original hydrogen index (HI) increase abruptly in the vicinityof Teshekpuk Lake in northeastern NPRA, and both parameters are relatively higheastward to the Shublik truncation edge beneath the eastern North Slope(Peterset al., 2006). We infer that the best oil potential in the Shublik occurswithin the shale-oil AU (defined by thermal maturity) from Teshekpuk Lakeeastward (Fig. 2). We infer good gas potential in the Shublik in the shale-gasAU across much of the North Slope (Fig. 2).
The Kingak Shale is divided into three map areas (Fig. 3) on the basis ofseismic and well-log character (Houseknecht and Bird, 2004). A broad area innorth-central NPRA contains a series of progradational shelf sequences, withinwhich Kingak source-rock facies are mostly limited to thin transgressivedeposits characterized by low values of TOC and HI. To the east and southeast,shelf deposits are absent and the lower Kingak comprises basinal condensedshale that has higher values of TOC and HI (Houseknecht and Bird, 2004; Peterset al., 2006). The Kingak is poorly known beneath the southwestern North Slopebecause of an absence of well penetrations (Fig. 3). We infer that the best oiland gas potential in the Kingak occurs within the shale-oil and shale-gas AUs,respectively, and basinward from the shelf sequences in north-central NPRA(Fig. 3). However, the paucity of brittle facies in the lower Kingak Shale maylimit its reservoir quality everywhere.
A map of the Brookian sequence showing thickness of net high gamma-ray (HGR)log response (cumulative thickness of gamma-ray response greater than 150 API)in the oil window (based on thermal maturity) delineates thermally mature areasthat may contain higher organic content (e.g., Schmoker, 1981). The map of netHGR displays complex patterns that reflect regional accommodation, localerosion beneath sequence-bounding unconformities, and thermal maturitypatterns. In general, net HGR thickens to the east (Fig. 4); this regionaltrend is consistent with patterns of TOC and interpreted original HI (Peters etal., 2006). Brittle facies closely associated with HGR intervals in theBrookian are more common east of NPRA. We therefore infer that the best oilpotential in the Brookian shale occurs in areas that contain more than 100 ftof HGR in the oil window, east of NPRA and west of ANWR (Fig. 4). The best gaspotential likely occurs within the shale-gas AU, in areas adjacent to the TransAlaska Pipeline System where the largest thickness of HGR is observed (Fig.4).
The USGS in 2012 completed the first-ever assessment of technicallyrecoverable shale-oil and shale-gas resources in northern Alaska. Aggregateestimates for all three source rocks range from 0 to 2 billion barrels of oiland 0 to 80 trillion cubic feet of gas (TCFG), with the ranges representing a95- to 5-percent probability of occurrence (Houseknecht et al., 2012b).Estimates for each source rock system include 0 to 928 million barrels of oil(MMBO) and 0 to 72 TCFG for the Shublik, 0 to 955 MMBO and 0 to 4 TCFG for theBrookian, and 0 to 117 MMBO for the Kingak (gas was not quantitatively assessedfor the Kingak). In all cases, the zero value at the 95-percent probabilityreflects the application of play-level risk. The Shublik is estimated tocontain the greatest oil and gas resource potential per unit area, with valuesthat rank among the top few source-rock systems in the United States.
The paper provides information on a unique vehicle, the amphibiousHoverbarge which can be used for transporting heavy cargo, modules and drillingrigs over Arctic terrain, such as snow, ice and tundra. The paper draws uponexperience of Hoverbarge operations in Alaska back in the 1970s along withrecent technical developments of the Hoverbarge to make it more suitable forArctic operations, including skirt ice protection and selfpropulsion.
The paper also highlights important environmental advantages the Hoverbargecan bring, hovering cargo and equipment above the tundra whilst only exerting1psi ground pressure. In addition the paper explains how the Hoverbarge canmeet current demands to extend operating seasons and transport heavy loads suchas pre fabricated modules without building new infrastructure.
Results, Observations and Conclusions
The paper also focuses on the potential of transporting cargo during summermonths when winter roads are not in use and the subsequent advantages that thisbrings.
Significance of Subject Matter
Although first developed over 35 years ago, the Hoverbarge remainsrelatively unknown to current day engineers. This paper seeks to increaseawareness of this technology which may solve a number of current logisticalissues.
Arif, Muhammad (University of Engineering and Technology) | Bhatti, Amanat Ali (University of Engineering and Technology) | Khan, Ahmed Saeed (University of Engineering and Technology) | Haider, Syed Afraz (Kuwait Foreign Petroleum Exploration Company (KUFPEC))
It has long been proved experimentally that the tight gas sands are more pronounced to stress changes as compared to moderate and high permeability reservoirs because of the narrow flow channels of the formation . The consideration of the effect of stress in the evaluation and production performance of tight gas reservoirs is very important in order to make right decisions regarding their development. Due to hydrocarbon production, the effective stress increases causing a reduction in permeability and porosity of the porous medium.
The conventional pressure transient analysis techniques in gas wells based on constant permeability would become unreliable . Consequently, the incorrect evaluation of permeability leads towards wrong decision regarding well stimulation. Also the inflow performance modeling of tight gas reservoirs based on constant permeability will not be corrected as far as evaluation of well's production potential is concerned.
Few studies on tight gas reservoirs considering the effect of stress sensitive permeability used the Raghavan's stress dependent pseudo-pressure approach  for which pressure vs. permeability data was determined experimentally. But, if laboratory data is not available then there is need to develop an analytical approach to generate the pressure vs. permeability data required for the use of stress dependent pseudo-pressure in reservoir evaluation and production performance studies in tight gas reservoirs.
The objective of this paper is to develop an analytical approach, in the absence of lab data, to generate pressure vs. permeability data for the determination of stress dependent pseudo-pressure. This stress dependent pseudo-pressure is used for well test analysis to determine the stress sensitive formation permeability and also to generate production performance in tight gas reservoirs. The developed technique has also been implemented on the field data of a tight gas reservoir to validate the results by using actual well's production history.
The hunt for further oil and gas recovery from old wells isbooming, and the industry look to new and improved technology for addingseveral years of operational time to exicting wells. New methods like lightwell intervention procedures sets high stress on old wellheads andinfrastructure, and a general increase in development of marginal fields haveraised issues over safety aspects.
Aside from developing improved procedures around cementingoperations, leakage detection and oil spill recovery, additional successfactors will be the ability to monitor pressure and temperature fluctuations inB annulus, as well as finding models and produce technology to manage suchpressure build upsuccessfully.
This paper introduces a new method of B-annulus monitoring using ultrasoundsignals originating from a device in the A-annulus providing measurements basedon time of flight in chambers placed in the B-annulus as a means of determiningthe temperature and pressure in the B-annulus.