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.
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.
Fracture ballooning usually occurs in naturally fractured reservoirs and is often mistakenly regarded as an influx of formation fluid, which may lead to misdiagnosed results in costly operations. In order to treat this phenomenon and to distinguish it from conventional losses or kicks, several mechanisms and models have been developed. Among these mechanisms under which borehole ballooning in naturally fractured reservoirs take place, opening/closing of natural fractures plays a dominant role. In this study a mathematical model is developed for mud invasion through an arbitrarily inclined, deformable, rectangular fracture with a limited extension. A governing equation is derived based on equations of change and lubrication approximation theory (Reynolds’s Equation). The equation is then solved numerically using finite difference method. Considering an exponential pressure-aperture deformation law and a yield-power-law fluid rheology has made this model more general and much closer to the reality than the previous ones. Describing fluid rheology with yield-power-law model makes the governing equation a versatile model because it includes various types of drilling mud rheology, i.e., Newtonian fluids, Bingham-plastic fluids, power-law, and yield-power-law rheological models. Sensitivity analysis on some parameters related to the physical properties of the fracture shows how fracture extension, aspect ratio and length, and location of wellbore can influence fracture ballooning. The proposed model can also be useful for minimizing the amount of mud loss by understanding the effect of fracture mechanical parameters on the ballooning, and for predicting rate of mud loss at different formation pressures.
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.
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 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'.
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.
Sanyal, Tirtharenu (Kuwait Oil Company) | Al-Hamad, Khairyah (KOC) | Jain, Anil Kumar (KOC) | Al-Haddad, Ali Abbas (KISR) | Kholosy, Sohib (KISR) | Ali, Mohammad A.J. (Kuwait Inst. Scientific Rsch.) | Abu Sennah, Heba Farag (Kuwait Oil Company)
Improved oil recovery for heavy oil reservoirs is becoming a new research study for Kuwaiti reservoirs. There are two mechanisms for improved oil recovery by thermal methods. The first method is to heat the oil to higher temperatures, and thereby, decrease its viscosity for improved mobility. The second mechanism is similar to water flooding, in which oil is displaced to the production wells. While more steam is needed for this method than for the cyclic method, it is typically more effective at recovering a larger portion of the oil.
Steam injection heats up the oil and reduce its viscosity for better mobility and higher sweep efficiency. During this process, the velocity of the moving oil increases with lower viscosity oil; and thus, the heated zone around the injection well will have high velocity. The increase of velocity in an unconsolidated formation is usually accompanied with sand movement in the reservoir creating a potential problem.
The objective of this study was to understand the effect of flowrate and viscosity on sand production in heavy oil reservoir that is subjected for thermal recovery process. The results would be useful for designing completion under steam injection where the viscosity of the oil is expected to change due to thermal operations.
A total of 21 representative core samples were selected from different wells in Kuwait. A reservoir condition core flooding system was used to flow oil into the core plugs and to examine sand production. Initially, the baseline liquid permeability was measured with low viscosity oil and low flowrate. Then, the flowrate was increased gradually and monitored to establish the value for sand movement for each plug sample. At the end of the test, the produced oil containing sand was filtered for sand content.
The result showed that sand production increased with higher viscosity oil and high flowrate. However, sand compaction at the injection face of the cores was more significant than sand production. In addition, high confining pressure contributes to additional sand production. The average critical velocity was estimated ranged from 18 to 257 ft/day for the 0.74 cp oil, 2 to 121 ft/day for the 16 cp oil, and 1 to 26 ft/day for the 684 cp oil.
Nowadays the energy demand has become tripled resulting in advancing of the development activities in the petroleum industry to enhance hydrocarbon recoveries. It is reviewed from the literature that the current worldwide facts of research and technical observations have proved that the coal containing methane gas is not much efficient in terms of power, cost and environment friendly energy source. The objective of this research is to determine the technical and economic feasibility of carbon dioxide (CO2)and nitrogen gas (N2). Moreover, sequestration in coal seams and their environmental consequences for coal based methane recovery project. This research study is also covers the effective and efficient methodology for extraction of methane gas from coal, which is coupled with the injection of CO2 and N2 into the coal seam complex structure. Moreover, this methodology is applied individually and simultaneously, along with the after effects of injection of CO2 and N2 on Coal bed methane (CBM) recovery. The results of this research study suggests a method for generation of electric power in which CBM gas is used as an input source whilst the combustion gas, CO2 emissions are sequestrated into coal seams for environmental protection, extending the CBM recovery and reducing CO2 availability cost.
Coalbed methane development has been grown rapidly from the last decades because of coal containing methane gas is more powerful, cheaper and environmental friendly hydrocarbon. It is also reviewed from literature that through Enhanced Coal bed methane (ECBM) between 30% and 60% recovery would be achieved. Based on pilot and simulation exercises, ECBM may be able to boost these recovery rates by an additional 20% to 30%.
When subsurface storage of anthropogenic Carbon dioxide is considered, among the geological formations, coal seams preserve a unique place with distinct gas trapping mechanism. Under the subsurface conditions and depending upon the thermal maturity of Coal, CO2sorption capacity of coal is typically 2-10 greater than for methane CH4 . This
is significant observation is highly considered not only for CO2 sequestration but also the production of Coal bed Methane. Moreover from production point of view as it implicitly points out stronger affinity of CO2 to the coal material. In addition, CO2 Sequestration also helps to lessen the environmental impacts including global warming, greenhouse gas effect and anthropogenic hazards.
The explosive growth of shale gas production in the US has sparked a global race to determine which other regions from around the world have the potential to replicate this success. One of the main areas of focus is the Asia Pacific region, specifically Pakistan.
In this paper, real results from seven different US shale basins- Marcellus, Eagle Ford, Haynesville, Barnett, Woodford (West-Central Oklahoma), Fayetteville and Bakken- have been used to develop a comprehensive sequence of shale exploitation strategy for emerging shale plays. The study involves integration of shale gas exploitation knowledge reinforced by a decade of experience across most of the North American shale gas basins, with published data. Different reservoir properties have been compared to develop a comprehensive logic of the effective techniques to produce from shale-gas reservoirs. We have validated the sequence with real results from US shale production ventures, published case histories, and by global experts who have been directly involved in shale reserves evaluation and production.
Subsequently, several different reservoir attributes of Pakistan shale plays have been compared with US basins, in an attempt to identify analogues.
It is the intent of this paper to diminish the difficult and often expensive learning cycle time associated with a commercially successful shale project, as well as to attempt to illustrate the most influential factors that determine optimum production. A very few papers in the petroleum literature that provide an extensive and systematic approach towards shale exploitation strategy for given shale-reservoir conditions
Encouraged by the U.S. successful experience with shale plays, many Asia Pacific countries including China and India - having 1275 & 63 TCF of technically recoverable Shale gas respectively - have already started off with aggressive plans to exploit their vast shale reserves.
Pakistan is currently suffering an energy shortfall of 2.3 BCF and the energy demand is expected to increase further by 245% until 2022, as compared to 2008. As its conventional reserves deplete, there is a need to work on new frontiers of energy sources. Unconventional gas resources, such as shale gas, tight gas and coal bed methane, are the avenues that should be focused on, in the current scenario.
According to EIA estimates, Pakistan's total Risked Gas in Place is 206 TCF, while its Technically Producible Shale Reserves are 51 TCF. It is interesting to compare these postulations with the Sui gas field serving the energy needs of Pakistan for decades, and having an estimated original recoverable reserve of 12 TCF. However, efforts to develop this potential resource have been lacking perhaps due to the economic and technological challenges.