For mature oil fields with complicated reservoir architecture, reservoir surveillance is key to track reservoir performance. Reservoir surveillance may include various monitoring tools from complicated horizontal production logging tools down to regular well tests. One of the main surveillance methods is running formation pressure measurement tools such as Formation Pressure Testers (FPT) or as historically known to the industry, Repeated Formation Tester (RFT). This paper describes the use of this important tool integrated with production data to understand reservoir production and depletion behavior and hence support the Bahrain Field development plan.
A study was conducted on the Ostracod and Magwa reservoirs; complicated carbonate reservoirs in the Bahrain Field. The Ostracod Zone is a sequence of inter-bedded limestone and shale in the upper Rumaila formation of the middle Cretaceous Wasia group. It is over 200 feet thick and consists of three main units: B0, B1, and B2. The Magwa reservoir is the lower member of the Rumaila Formation. It is 120 feet thick and conformably underlies the Ostracod reservoir. It consists of three main units: M1, M2, and M3.
The main objectives of this study are:
Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate. Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location. Evaluating the Ostracod/Magwa pressure depletion per unit with time. Linking the pressure depletion to the cumulative production from the area offset by the FPT data.
Evaluating pressure depletion from the initial reservoir pressure for each unit in both reservoirs, which defined the existence of flow barriers in this inter-bedded complicated carbonate.
Evaluating the relationship between pressure depletion in each unit and the spacing between offset wells to the FPT location.
Evaluating the Ostracod/Magwa pressure depletion per unit with time.
Linking the pressure depletion to the cumulative production from the area offset by the FPT data.
The results of this study helped define the depletion risk on the future infill opportunities in such complicated reservoirs. It also helped in locating highly depleted units and determining the optimal locations for the new infill wells.
Al-Obaidli, Asmaa (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Al-Shammari, Obaid (KOC) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Amjad, Yaser Muhammad (Schlumberger) | Gonzalez, Doris (BP) | Gonzalez, Fabio (BP)
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirtysix (36) producer wells have been drilled until now. By 1999, when the field had accumulated 92 MMSTB of produced oil and the reservoir pressure had declined to 8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core-flooding study and 1 permeability/wettability study. Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 500 psia and the saturation pressure is 3,200 200 psia. Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates.
Najaf, A. A. (Kuwait Oil Company) | Ramchandra, A. (Kuwait Oil Company) | Al-Yetama, M. (Kuwait Oil Company) | Ledesma, F. (Weatherford International) | Al-Salman, A. (Weatherford International) | Suleiman, N. (Weatherford International)
Progressing cavity pump (PCP) systems are widely used in the oil and gas industry. Continuously evaluating PCP performance helps to maximize and sustain fluid production and increase pump run-life. This paper focuses on integrating a real-time platform and advanced software to model, troubleshoot, and optimize PCP systems and their operation.
More than 50% of installed PCP systems located in Great Burgan Field in southeast Kuwait are connected to a real-time SCADA platform. These connected systems are monitored to support daily operations and to identify underperforming wells for troubleshooting. Special attention is given to wells exhibiting critical behaviors or wells with optimization opportunities. Before implementing any actions on these wells, real-time data history is used along with nodal analysis to predict the outcomes. This paper presents an intensive optimization analysis through the following field case studies: Preventing sucker rod string failure Evaluating pump submergence Optimizing fluid production Identifying optimum operating conditions
Preventing sucker rod string failure
Evaluating pump submergence
Optimizing fluid production
Identifying optimum operating conditions
Software is used to perform simulations of flow under different operating conditions and to generate a full analysis report based on PCP equipment configured in the well model. The sharp-edge results are not limited to the production rate. They also extend to pump performance and other surface and downhole parameters such as pump torque, intake pressure, and discharge pressure. The outcome of these results assists with making well-informed decisions with the following benefits: Operating conditions have been improved by estimating the production rate at different speeds. Pump life has been improved by evaluating rod load, lift load, and efficiency. Down-time has been reduced by preventing pump-off conditions.
Operating conditions have been improved by estimating the production rate at different speeds.
Pump life has been improved by evaluating rod load, lift load, and efficiency.
Down-time has been reduced by preventing pump-off conditions.
The procedure serves as a proven guide for analysis and optimization of PCP systems. Improving pump efficiency, achieving the target production rate, identifying problems, and preventing potential failures all help to optimize PCP system performance.
The innovative integration of PCP analysis and optimization provides a means to increase production and reduce the load percentage of surface and subsurface equipment parameters. A real-time SCADA platform combined with the optimization software created an ideal solution to keep wells operating at peak performance levels.
Al-Enezi, Bashar (Kuwait Oil Company) | Kostic, Boris (Badley Ashton & Associates Ltd) | Foote, Nicolas (Badley Ashton & Associates Ltd) | Filak, Jean Michel (Kuwait Oil Company) | Al-Mahmeed, Fatimah (Kuwait Oil Company) | Al-Shammari, Obaid (Kuwait Oil Company) | Bertouche, Meriem (Badley Ashton & Associates Ltd)
Resistivity image logs are high-resolution tools that can help to unravel the depositional and structural organisation in a wellbore. They provide a particularly powerful dataset when calibrated against core, maximising their benefit for reservoir characterisation. This paper shows examples how very detailed image assessment from selected wells in the Greater Burgan Field has helped to constrain the stratigraphic model and depositional interpretations of the Cretaceous Burgan and Wara reservoirs.
A multidisciplinary study of 123 cored wells, integrating core sedimentology, petrography, bio- and chemostratigraphy, wireline well and resistivity image logs, has delivered a robust stratigraphic and depositional framework for one of the most important reservoirs in the world's largest siliciclastic oil field. A descriptive image facies scheme that has been calibrated against core and conventional well logs captures the lithological variation, sedimentary features and surfaces of the reservoir, providing a detailed proxy for the sedimentological evaluation of uncored intervals and wells.
The sand-rich lower Burgan (4S) comprises fine to very coarse-grained fluvial channel sandbodies that are locally separated by laterally restricted mudrock baffles. Image and core analyses suggest that the majority of the sandstones are high-angle cross-stratified and form stacked barforms within amalgamated channel sandbodies. Their consistent orientation towards the NE-E supports a low-sinuosity (braided) fluvial system resulting in a relatively simple, sheet-like depositional architecture across the field. Although slightly finer grained, the cored middle Burgan channel sandbodies (3SM) are similar to those in the lower Burgan. However, palaeoflow data from the imaged wells show a higher directional spread in the order of
The examples from the Burgan and Wara Formations highlight the value of integrated image analysis for reservoir characterisation by delivering a consistent descriptive framework, embedding different datasets.
Rahaman, Mafizar (Kuwait Oil Company) | Hafez, Mohamed (Kuwait Oil Company) | Ibrahem, Al-Saleh Lulwa (Kuwait Oil Company) | Mudavakkat, Anandan (Kuwait Oil Company) | Rajagopal, Rajesh (Kuwait Oil Company)
This paper presents the use of prestack geostatistical inversion (PGI) technique, for the delineation of thin sand intervals in the Wara Formations in the Magwa and Ahmadi fields, Kuwait. In this area, Wara Formations is predominantly sand and shale sequences, with higher proportion of shaliness compared to the adjacent Burgan field. Wara sands are good producers of hydrocarbon in the study area. The low P-impedance contrast between the sand and shale makes P-Impedance ineffective to discriminate them. The Vp/Vs ratio from the PGI is found to effectively discriminate these sand units from shale.
The main inputs for PGI study are well log data, well log statistics and seismic angle stack data. Petrophysical analysis was carried out, which is essential for identifying reservoir facies. Two lithologies in Wara Formation are defined using well log analysis with Vshale cut off. Detailed well log statistics analysis (vertical size, layer constraints and lithology proportions) was carried out, which is also a primary input for the PGI study. Seismic angle stacks were aligned and amplitude-balancing were also carried out. After obtaining optimized inversion parameters, PGI was run. It provided the multiple plausible realizations of P-impedance, S-impedance, Vp/Vs and lithology volumes, which are further used and co-simulated to generate porosity volumes. Porosity and most probable lithology volumes were generated for mapping the reservoir distribution in the area. Two blind test results provided good match and further determined the reliability of the PGI. The study shows additional porosity development towards north eastern part of Magwa and Ahmadi fields.
Presentation Date: Tuesday, October 16, 2018
Start Time: 9:20:00 AM
Location: Poster Station 7
Presentation Type: Poster
Singavarapu, Anjaneyulu (Kuwait Oil Company) | Singh, Sunil Kumar (Kuwait Oil Company) | Al-Ajmi, Afrah (Kuwait Oil Company) | Dey, Arun (Kuwait Oil Company) | Al-Busairi, Abdulaziz (Kuwait Oil Company) | Al-Azmi, Khalid (Kuwait Oil Company) | Roy, Mrinmoy (Kuwait Oil Company)
Exploration for Hydrocarbon accumulations in Tertiary Rus, Radhuma formations have not been given serious attention until recently in the State of Kuwait. After the successful discovery and production of hydrocarbons from the shallow reservoirs of Lower Fars in North Kuwait, the focus shifted into exploration of other shallow Tertiary reservoirs in Kuwait. The hydrocarbon shows encountered in Rus, Radhuma sections during the drilling of deeper Cretaceous wells in Burgan and Magwa areas and the production from these reservoirs in the neighboring Wafra field made these shallow reservoirs in Greater Burgan area a potential target for exploration.
A detailed analysis of the mapped structure with the hydrocarbon indications both on and off the structures observed in the mud logs of wells in the area indicates that the present day structural configuration does not fully explain these hydrocarbon accumulations and the play appears to be primarily strati-structural in nature. Keeping this in mind, an integrated approach had been adopted in relating the seismic data with hydrocarbon indications and their subsequent correlation through a combination of seismic attributes like discontinuity analysis, instantaneous frequency, phase, RMS amplitude, spectral decomposition as well as waveform classification coupled with impedance data. A suitable geologic model has been postulated with seismic which is calibrated with the petro physical data and the results are validated by the good oil and gas shows in quite a few drilled wells in the area and resulted in identifying a target area for exploration. Additionally, the study further identified a major seismic amplitude anomaly in Magwa area, which is characterized with a big pay in Mid Radhuma reservoir. The study has established that systematic workflow adopted through integrated analysis of seismic attributes is the key in defining reservoir geometry and resulting in deciphering a new stratigraphic play in rich petroliferous province like Kuwait.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: Poster Station 1
Presentation Type: Poster
The 16″ Vertical Performance Motor Section is the most challenging section in Exploration Deep Drilling in Burgan Field & All South East Kuwait. The section comprises drilling hard and abrasive Zubair formation followed by reactive Ratawi Shale formation. Several technologies were introduced during the last ten years in search of an economic solution to deliver this section safer and faster with limited success. The objective of this paper is to present the process and technology implemented to drill Zubair and Ratawi Shale formations in two different wells with the same bit at record rates of penetration.
Bit durability is generally the main driver in the 16″ section performance. Historically, one to two polycrystalline diamond compact (PDC) bits were utilized in this section and were pulled out for low penetration rates. The new solution required a thorough offset data analysis, including formation porosity, rock strength and abrasiveness analysis, applied drilling parameters and Mechanical Specific Energy (MSE) analysis using software. A customized PDC bit design was then developed using a state of the art bit/formation interaction model combined with an advanced cutter technology and hydraulics pairing for ultimate cutter cooling.
The new PDC bit design and the implementation of the softwares used to analyse offset wells drilling parameters and rock mechanics had a significant effect on the bit durability and Rate of Penetration (ROP). The optimized drilling parameters applied as per the former set roadmap aided in managing the bit cutting structure through Zubair and Ratawi Shale formations and the bit was pulled out in re-runnable condition with a new field ROP record. The same bit was then used again in different well and drilled Zubair and Ratawi Shale formations and pulled out with 1, 3 dull condition. Over the two wells drilled, the optimized drilling plan saved National Oil Company over US $200,000, reducing the cost per foot (CPF) drilled by 38% over the field average CPF, increasing the ROP by 55% over the field average and drilling 69% footage more than the previous section benchmark footage.
With the engineering evaluation of the offset data and the utilization of the new bit design, National Oil Company managed to drill Zubair and Ratawi Shale section in two different wells with the same bit for the first time and was able to improve drilling efficiency and cutting the drilling cost by eliminating bit trips and cost of new PDC bits.
Hawie, N. (Beicip-Franlab) | Dubille, M. (Beicip-Franlab) | Guyomar, N. (Beicip-Franlab) | Maury, G. (Beicip-Franlab) | Thomas, V. (Beicip-Franlab) | Vidal, O. (Beicip-Franlab) | Carayon, V. (Beicip-Franlab) | Cuilhe, L. (Beicip-Franlab) | Al-Sahlan, G. (Kuwait Oil Company) | Al-Ali, S. (Kuwait Oil Company) | Al-Khamis, A. (Kuwait Oil Company) | Dawwas Al-Ajmi, M. (Kuwait Oil Company)
Hydrocarbon exploration along the Arabian Peninsula is almost celebrating a century of successes. Major structures were drilled and hundreds of billions of barrels consequently discovered and still producing at increasing rates. Remarkable multi-scale and multi-disciplinary dataset (e.g., 2D, 3D seismic data, core and well log data and imagery…) have been acquired in the past decades allowing geoscientists to better assess the diverse onshore and offshore Petroleum Systems’ potential. Many challenges linked to the exploration of new hydrocarbon resources in such Mature Basins are driving innovative ideas towards the identification, the assessment and the de-risking of new subtle Plays. "Integration" remains a key problematic that needs to be tackled in order to answer properly to how much resources are still left unexplored. Thus, multi-disciplinary expertise, multi-scale dataset combination should be supported by recent technological advances in data acquisition and processing (e.g., 3D Seismic inversion and characterization) as well as by integrated modelling approaches (e.g., 4D Forward Stratigraphic and Basin Modelling).
This paper discusses the results of an innovative methodology developed to assess the exploration potential of the Lower Cretaceous along a wide sector of the mature Eastern Arabian Plate that extends over more than 35 000 km2 (Onshore and Offshore Kuwait).
As major structural features have already been drilled, a focus is set on the detection of subtle stratigraphic trapping mechanisms using multi-disciplinary and multi-scale sedimentological, stratigraphic, petrophysical and geophysical techniques. Seismic stratigraphy study based on reflectors configuration and internal geometry analysis has enabled the delineation of geobodies, i.e. reservoir/seal pairs and proposed conceptual models associated to the presence of subtle traps. A regional
This innovative and integrated workflow applied in mature sectors of the Arabian Plate sets new grounds for the generation of regional Play Fairway Maps, Common Risk Maps for the different Petroleum systems elements (reservoir, seal, trap and charge) as well as Composite Common Risk Maps. These tasks are aimed at assessing the overall risk associated to Plays and thus contribute to the identification of new exploration Lead Areas to be further de-risked in the near future.
The Greater Burgan Field is located onshore southern part of Kuwait and it is the world's largest clastic field. A low-relief anticlinal dome draped over a basement horst structure defines it. The primary producing reservoirs are the Wara and Burgan of Cretaceous age. Burgan field has been developed by drilling more than 1000 wells mainly targeting Burgan reservoir. Majority of the wells were planned and drilled in the low risk / low uncertainty part of the field, where the combination of the shallow structure and good quality reservoir facies allowed drilling till date. Since the wells density has increased in the dome area and the area congested with surface facilities, biggest challenge lies in identifying locations in the flank and rising flank part of the field.
As the demand for oil increases rapidly and the need to sustain production from ageing wells is necessary, more new wells needed. Placing increased number of infill wells, while maintaining the proper reservoir management is a major challenge. In order to plan the wells in a way that maximizes the productivity and optimizes the economy; a study was conducted to analyse the density of the wells and the impact on reservoir behaviour. This comprehensive study targeted area "A" which is in the middle of the field, that is characterized by it's well developed facies, massive oil column and the lateral connectivity of the sand. Well correlations, OWC movement, production rates, density of the wells and the spacing were extensively analysed and a way forward for new infill and well planning was established.
The established way forward used to plan the new infill and to design the trajectory of the wells. Based on that new locations were identified to be drilled away from our comfortable area ranging from low to high-risk locations, where the highly heterogeneous sands and the relatively low structural levels increased the level of uncertainty adding to that the chances of oil might be already drained by the offset up dip wells. In order to lower the level of uncertainty several seismic attributes were included in the planning phase. One of the powerful attributes used is the genetic inversion, which is adopting the same approach as the neural network.
Two different seismic volumes differ in the size were trained using well logs data, then QCed with the existing wells. The smaller seismic volume was highly correlatable to the actual data and more reliable compared to the larger volume. The integrated volume was used in the locations identification and planning process. Subsequently all the identified locations released planned and drilled within one year. The results were promising as the encountered oil column in each well exceeded our expectations considering the high risk factor presented in each location. These findings has opened the door to investigate more and widely in the challenging or unestablished part of the field where good opportunities still exist in the structural trends/unestablished part of the field, where minor faults and various facies changes act as a barrier for oil accumulation.
The aim of this paper is to shade some lights on the current challenges in the Brown field development and to emphasize on "No risk no gain". This comprehensive paper will illustrate the importance of proper data integration, the methodology used in the well planning and the successful post drilling results, the results of this study will guide on the future infill drilling.
Gazi, Naz H. (KOC) | Al-Othman, Mohammad (KOC) | Tirkey, Naween (KOC) | Al-Sabea, Salem (KOC) | Ali, Farida (KOC) | Abdulrazzaq, Eman (KOC) | Ahsan, Mohammad J. (KOC) | Al-Menai, Deema (KOC) | Anwar, Ahmed Mokhtar (Schlumberger) | Mahmoud, Wael (Schlumberger) | Taramov, Musa (Schlumberger) | Sheikh, Bilal (Schlumberger)
In the MG field located in the South east of the State of Kuwait, the 3rd Sand Upper deposits are found at depths of nearly 4000 ft and feature a more complex geological structure when compared to the greater Burgan deposits. Furthermore, the 3rd Sand upper deposits feature multiple successive layers with different lithology with low reservoir pressure (1500 psi) & temperature (135F). To achieve economic well production from such formation, conventional stimulation techniques have been applied & showed minor none economical production. Accordingly, the 3rd Sand upper reservoir are kept undeveloped looking for solutions.
Conventional Hydraulic fracturing Techniques are well known as a reliable method for increasing well productivity from the tight & heterogeneous reservoirs. However, it will not be applicable in the 3rd Sand upper reservoirs mainly due to; 1) the operational challenge of placing successfully huge fracturing treatment to achieve the desired longest possible fracture geometry, 2) the difficulties of flowing back the huge quantities of the guar based fracturing fluids in such low pressure-low temperature reservoir. Failure place sufficiently massive treatment or flow back of fracturing fluids will reduce the effective fracture half length & compromise the full production potential.
Recently, the Channel-Fracturing technique has been successfully applied in 5 wells in MG field with same reservoir challenges explained above. The Channel-Fracturing techniques changed the concept of the hydraulic fracturing & overcome its disadvantages. Whereas the conventional fracturing treatments rely mainly on the placing as huge as possible proppant mass & its associated carrying fluids, the Channel-Fracturing technique concept relies on creating open-flow channels utilizing less proppant quantities. Pulses with proppant are separated by pulses of clean fluid, which creates proppant clusters inside the fracture &holding the walls of the fracture open.
The channel-Fracturing techniques will ensure longer effective fracture half-length and, consequently, production rates. In addition, to the reduced required proppant quantities which reduced the placement risk & material cost, one of those wells was customized massive Channel-Fracturing treatment for the first candidate well in the field to place 350KLB of proppant equivalent to 800 KLB of a conventional treatment to achieve +/- 500ft of effective fracture half-length laterally in the 3 Sand upper reservoir. The Treatments has been executed successfully throughout the whole campaign as designed without any pre mature sand screen out or completion failure due to pressure build up. Then the well opened to flow & showed a natural flow of 200% compared to the estimated gain. The treatment bottom hole pressures analysis clearly identified a signature of a successful treatment. The successful results in this campaign managed to unlock the reserve and allow development of the 3rd Sand upper reservoir in the SEK fields.