Mauddud Formation is a major oil-producing reservoir in Raudhatain Field of North Kuwait. The Mauddud Formation is an early Albian in age and it was generated an environment of the shallow-water carbonate and consists of Grainstones, Wackestones and Mudstones deposited in ramp settings. In Raudhatain field (RAMA) is undertaking massive development efforts with planned enhancement in Oil production. Reservoir description and distribution of rock properties in 3D space are challenging due to inherent reservoir heterogeneity, in this case primarily driven by depositional and diagenetic patterns.
KOC North Kuwait Reservoir Studies Team (NK RST) has been challenged to increase the production from several key NK oil fields. To achieve this goal, KOC has partnered with Schlumberger to rebuild integrated model with Petrophysics, Geophysics, and Geology and Reservoir data of the Mauddud Reservoir. The original model was required to minimize challenges in new infill locations, increase Oil recovery factor and detect water breakthrough to minimize water production. One of the key issues in creating RAMA reservoir model is integration of all available data in identifying the horizontal permeability, reservoir heterogeneity and identification of thief zones.
A fine Geological grid model with 35M cells, 10 Geological horizons has been built to characterize the Mauddud reservoirs of the RAMA field including the permeability from PLT logs combined with petrophysical and lithological / facies data to add more understanding of the distribution of reservoir properties. Log response group methodology and the undeveloped area in the Saddle (structurally low area) has been modelled for the first time in Raudhatain NK Field. This combined study utilizes the available data and cutting-edge technology using Geo2Flow which resulted in fluid compartmentalization and free water level identification. STOOIP has been upgraded and unlocking potential in new segments of the developed field. The original model was built based on vertical/Deviation wells (345) which lead to discrepancies in the structural interpretation. The new update has been carried out including all horizontal wells to minimize the uncertainty in the structure framework.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Presence of H2S detected in producing wells of North Kuwait sweet waterflooded reservoirs over the last 18 years, gave indications of biogenic souring. In response to this, the Kuwait Oil Company engaged in detailed souring potential assessments of selected reservoirs such as the Raudhatain Mauddud (RAMA), to predict the further generation of H2S and define the required souring mitigation strategy to ensure safe production over the remaining field life.
The souring simulation modelling was conducted on the RAMA subsurface model with support from Shell, using a state of the art souring prediction program. The initial phase of the study consisted in the history match simulation to define the most likely souring mechanism in the field. The forecast considered various scenarios with a range of sensitivities on carbon nutrient and sulphate levels, both in formation and injected water in the field.
The history match simulation results showed a good correlation with most of the producers with available H2S data. The Forecast simulation over the next 15-year period predicts a moderate souring severity for this reservoir, based on the maximum H2S mass flow rate of 90 kg/d and H2S in gas maximum concentration of 85 ppmv at the field level.
This work provides the petroleum Industry further insights into the souring behavior when effluent water is injected in addition to seawater, particularly the effects of additional carbon nutrients fed into the reservoir.
One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.
The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.
Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.
Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
Velázquez-Cruz, D. (Instituto Mexicano Del Petróleo) | Espinosa-Castañeda, G. (Instituto Mexicano Del Petróleo) | Díaz-Viera, M. A. (Instituto Mexicano Del Petróleo) | Leyte-Guerrero, F. (Instituto Mexicano Del Petróleo)
The pore pressure prediction is the most important process in the design of drilling wells. This paper depicts a new methodology to analyze pore pressure based on both, the normal compaction theory of sediments and the way that normal behavior diverges when it is interrupted. Much has been written on the topic; however, even today a high percentage of non-productive time (NPT) in drilling activities is related to pore pressure and wellbore instability problems. Here, a new methodology is proposed to improve the accuracy of calculated pore pressure from well logs and seismic data. Moreover, this new methodology allows, under specific conditions, to determine pore pressure in carbonates and other reservoir rocks. The compaction process defines the normal trend of porosity indicators with depth, the fluid retention depth and those rock bodies diverging from a normal compaction trend. The divergence detection procedure includes the identification of both, transitional changes of the porosity indicators (shale) and those that are parallel to normal compaction trend (reservoir rock); they allow to build a divergent area. When the divergent area is defined, the pore pressure calculation can be done using a pore pressure model based on normal compaction theory and well logs or interval velocity data from seismic. Misleading prediction of geopressures for a particular area are linked to: misunderstandings of pore pressure origins there, the limited scope of pore pressure models based on well logs and to miscalculations of the key parameters of pore pressure models. This work discuss the impact of these key parameters in the pore pressure prognosis. Analysis of actual cases showing the impact of miscalculation of overburden stress on pore pressure estimations, normal compaction trend definition and pore pressure calculations are presented using divergent area along with the Eaton model. The conclusions support the following statements: well log density data cannot be used to calculate the overburden pressure and under some conditions, the divergence methodology can be used to calculate pore pressures in carbonates. Furthermore, the divergent area method eliminate the use of shale points in pore pressure prognosis.
Recent drilling of moderately to highly deviated development wells in the Kilo Field has proven to be extremely challenging. Numerous lost-time incidents including stuck pipe, pack-off, and difficulties in running casing were experienced, particularly when drilling through the Main-Massive Formation. Earlier analyses pointed to mud material quality issues, but drilling performance benchmarking with other nearby fields ruled out this explanation. Faced with continually high NPTs, a geomechanical study was initiated to mitigate the wellbore instability problems. The recommendations arising from the comprehensive geomechanical and drilling experience analyses have been implemented to improve performance during subsequent development drilling.
The field-wide geomechanical model indicates the Kilo Field is characterized by a state of stress that is transitional between a normal and strike-slip faulting regimes. The combination of relatively large differential stress and relatively weak rocks means the field is potentially subject to stress-induced wellbore instability problems. However, observations of numerous time-dependent failures imply secondary influences must also be considered to arrive at possible remediation strategies. A systematic ranking process has been developed to delineate the primary causal mechanism of wellbore instability. This process suggests that the major contributor to the time-dependent deterioration process is rising pore pressure caused by the invasion of drilling fluid into micro-fractured formations, and then exacerbated by less-than-optimal drilling practices. This finding, together with the improved geomechanical understanding of the Kilo Field, provides the basis for optimizing mud weights and wellbore trajectories as well as formulating appropriate drilling strategies to maintain the mud hydrostatic support (overbalance) in future drilling. The finding also highlights the importance of integrating geomechanics with drilling practices when developing strategies to mitigate unstable hole problems.
This paper presents a comprehensive, ordered workflow that integrates the disparate data available in a mature field to identify the most likely causative mechanisms of the time-delayed wellbore instabilities. This knowledge was then used to develop strategies for optimizing future drilling operations in the Kilo Field.
Raji, Jamiudeen Kayode (Department of Petroleum Engineering and Geosciences, Petroleum Training Institute, Effurun, Delta State) | Adebowale, Ademola Olabisi J. (Department of Petroleum Engineering and Geosciences, Petroleum Training Institute, Effurun, Delta State)
Forty six (46) shale samples were collected from borehole, quarry and outcrop in the Northern Benue Trough which consists of Gongola and Yola Basins respectively. The Gongola Basin comprises Bima Formation, the Yolde Formation, Pindiga/Gongila Formation and capped with Gombe Formation whereas the Yola Bain consists of Bima Formation, Yolde Formation, Dukul/Jessu/Numanha Formation and capped with Lamja Formation. The samples were subjected to vitrinite reflectance, Rock Eval pyrolysis and infrared spectroscopy in order to evaluate their organic richness, thermal maturity and petroleum generating potential. The total organic carbon (TOC) values of the Gongola Basin are between 0.20 and 2.46 wt. % averaging 0.70 wt. % while that of Yola Basin range from 0.11 to 12.9 wt. % averaging 1.50 wt. %. The mean random vitrinite reflectance (Rom) values in the Gongola Basin range from 0.48% in the Gombe Formation to 0.65% in the Pindiga Formation and 0.67% in the Gongila Formation. Also, the reflectance values in the Yola Basin increase with stratigraphic age ranging from 0.63 to 0.80% in the Dukul and Yolde Formations respectively. The thermal maturity of the organic matter (Tmax) values from the pyrolysis of shales in the Gongola Basin is between 420 and 440°C while that of Yola Basin range from 435 to 445°C. The plot of hydrogen index (HI) vs Tmax for classification of kerogen in the Gongila and Pindiga Formations reveals prevalence of Type III kerogen while that of Dukul and Yolde Formations shows Type II – III kerogen. The results obtained suggest that Gongola Basin source rocks are fair and thermally immature to marginally mature and have potential to generate gas in the deeply buried section whereas the Yola Basin source rock are between fair to good and thermally mature with potential to generate oil and gas in the deeper section.
Wei, Ping (CNOOC Energy T&S Ltd.) | Lavoix, Frederic (Total E&P Indonesie) | Muryanto, Bonifasius (Total E&P Indonesie) | Nurrachman, Firman (Total E&P Indonesie) | Chaloupka, Vladimir (Total E&P Indonesie) | Landry, Jed (Superior Energy Services) | Chun Ming, Li (Superior Energy Services)
Multizone single trip sand control completions have been the mainstay in Indonesia for years. The paper reviews successful history of 7” gravel pack multizone completions including world’s first 7” and 9-5/8” multizone gravel packs run in one well. It presents application concerns when considering multizone systems, as well as lessons learnt from the presented cases.
Cased hole single trip multizone gravel pack systems have been used as a sand control solution for cost efficiency, the ability to complete multiple sands in a single trip and to provide zonal isolation for production selectivity. Among the main benefits is a single string washpipe system that enhances well control capabilities, the ability to complete longer intervals in one trip, and provides larger production capacity compared to dual string multizone washpipe systems. The 7” system can be also used as a contingency for cases where 9-5/8” casing cannot reach planned depth.
All 7” systems were deployed successfully as planned confirming expected rig time reduction of 8-10 days per well comparing to stacked gravel packs.
In one case, due to operational problems unrelated to the gravel pack system, an operator was able to pull service string out of hole before pumping gravel pack. Packers were then unset and the system fully retrieved without any difficulties in one trip. After solving the problems, the well was completed. In another case, the operator successfully installed 7” and 9-5/8” systems in one well after discovering additional reserves below the 9-5/8” casing shoe.
Not only was the 7” system proven to reduce costs for operators, but it also permitted significant flexibility in drilling and completion operations. The system is now considered as standard contingency for operators in cases where 9-5/8” shoe must be set higher than planned or when openhole completion cannot be run inside of 8-½” open hole.
Adedosu, T.A. (Ladoke Akintola University of Technology) | Ajayi, T.R. (Obafemi Awolowo University) | Xiong, Y. (Chinese Academy of Sciences - State Key Laboratory of Organic Geochemistry) | Li, Y. (Chinese Academy of Sciences - State Key Laboratory of Organic Geochemistry) | Fang, C. (Chinese Academy of Sciences - State Key Laboratory of Organic Geochemistry) | Chen, Y. (Chinese Academy of Sciences - State Key Laboratory of Organic Geochemistry) | Akinsehinwa, A. (Obafemi Awolowo University)
Twenty drilling cuttings were collected between the depth, 896.1 m and 2724.9 m from Kolmani River-1 well, Gongola basin, Upper Benue Trough Nigeria. The polycyclic aromatic hydrocarbons and heterocyclic compounds contained in the soluble organic matter of the samples were characterized by GC-FID and GC-MS and subsequently used to determine their source-depostional environment-, and thermal maturity. The samples contained between 2 to 6 rings polyaromatic hydrocarbons in varying proportions and the heterocycles include dibenzofuran- (DBF), flourene-(F),dibenzothiophene- (DBT), and their alkylated derivatives. The notable presence of 1,2,5-, 1,2,6-, and1,2,7-trimethylnaphthalenes, as well as 1,2,5,6-, 1,2,5,7-, 1,3,6,7-tetramethylnaphthalenes in the samples indicate angiosperm, gymnosperms and microbial input.
The predominance of 9-MP depicts strong presence of marine organic matter, while the occurrence of 1, 2, 8-trimethylphenanthrene reflects contribution from bacteria, algal or terrestrial materials. The occurrence of benzo (e) pyrene, benzo(a) pyrene, perylene, benzo (k+b) fluoranthene and benzo (g,h,i) perylene as well as, biphenyls, F, DBF, DBT and their alkylated derivatives in the samples might reflect input from phytoplankton and significant incorporation of terrestrial material in some Gombe and Yolde samples. Also, the predominance of alkyldibenzothiophenes reveals that source rocks are majorly from a marine anoxic-suboxic depositional environment. The chry/phen (0.23-3.12) and 2-+9- B(a)Anth/2-MC (0.13-6.74) showed that the organic matter were deposited in terrestrial to marine/lacustrine (Gombe formation), marine/lacustrine (Pindiga and Yolde) and Bima (lacustrine) environment. The (TeMN), %Rc, MPI-1, MDR, 2-MC/1-MC, MCHR and Fl/Fl+Py range from 0.19-0.52, 0.62-0.94, 0.92-4.68, 0.29-1.39, 0.1-0.43 and 0.32-0.86. These values showed that the relatively mature zone falls within the Yolde formation (2140 m – 2578.6 m). However, relatively high value of Fl/Fl+Fy ratio (0.86) recorded in K11 (Gombe) might reflect expulsion of hydrocarbons from this source-rock to yet-to-be identified reservoir rock.
The Enterprise Standard of Method for Petroleum Initial Reserves Evaluation in China prescribes the economic limit production prediction model is the standard evaluation method of the developed oil and gas initial reserves. This model is derived from the theory of input-output balance, and the important key is the clear classification of fixed cost and variable cost in use of this model. Owing to the composite of operating cost, it is difficult to divide the operating costs into fixed costs and variable costs, therefore affects the evaluation accuracy of the initial reserves to a certain extent. Due to more and more oilfields entering the middle to later development stage, the measures of increasing production and the development mode change become the important ways for holding and increasing production, thus cause the differences of cost structure in different stages, therefore the difficulty of cost classification and the uncertainty of initial reserves evaluation are increasing obviously.
In order to avoid the cost classification errors and evaluation effects of proved recoverable reserves, this paper sets up an economic limit of oil production prediction model derived from the discounted cash flow method. Furthermore, this paper puts the prediction model and Petrochina Standard's model and D&M Co.'s simple calculating formula comparison. The comparison study shows several differences among the three models on formula derive basis, cost preferences and government revenues. Cases analysis shows important conclusions as follows, first, the cost classification was not involved in model calculation process; thereby multiple solutions from the economic limit production calculation were avoided effectively. Second, the model standardizes the costs preference and its assignment, and then improves the economic limit prediction accuracy. Third, the formulas determined by this model can conveniently complete the scenario analysis of the oil price, cost, government revenue and other factors.