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.
Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
The Middle Minagish Oolite Formation is 450 to 550 feet thick interval of porous limestone reservoir, composed of peloidal/skeletal grainstones with lesser amount of packstone, oolitic grainstone, wackstone and mudstone in Umm Gudair field, West Kuwait. It is characterized by small scale reservoir heterogeneity, primarily related to the depositional as well as diagenetic features. Capturing reservoir properties in micro scale and its spatial variation needs special attention in this reservoir due to its inherent anisotropy. Reservoir properties will depend on the level that we are analyzing on reservoir (millimeter to meter scale). Here we used Electrical Borehole Image (EBI) and Nuclear Magnetic Resonance (NMR) to capture small scale feature of Umm Gudair carbonate reservoir and compared them with core data
In present work, reservoir properties (including texture, facies, porosity and permeability) interpreted by the EBI shows good match with NMR driven properties and core data. Textural changes in image logs also match well with pore size distribution from NMR logs. Further highly porous zones which are considered either due to primary porosity or vugs match with larger pores of NMR logs and these corroborates with also core derived porosity. A good match has been observed between EBI, NMR and cored derived porosity. Permeability calculations have also been made and compared with core data. A detail workflow has been developed here to interpret reservoir properties on un-cored wells, where only low vertical resolution data is available. This technique is quite useful to identify the characters and mode of origin highly porous zones in reservoir section which are generally not identifiable by low resolution standard logs. This workflow will allow us to interpret the heterogeneity at high resolution level in un-cored wells, as results are validated with integration of EBI, NMR and core data.
During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid.
It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid.
It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.
Gomez, Ernest (Schlumberger) | Al-Faresi, Fahad A. Rahman (Kuwait Oil Company) | Belobraydic, Matthew Louis (Schlumberger) | Yaser, Muhammad (Schlumberger) | Gurpinar, Omer M. (Schlumberger) | Wang, James Tak Ming (Schlumberger) | Husain, Riyasat (Kuwait Oil Company) | Clark, William (Schlumberger) | Al-Sahlan, Ghaida Abdullah (Kuwait Oil Company) | Datta, Kalyanbrata (KOC) | Mudavakkat, Anandan (KOC) | Bond, Deryck John (Kuwait Oil Company) | Crittenden, Stephen J. (KOC) | Iwere, Fabian Oritsebemigho (Schlumberger) | Hayat, Laila (KOC) | Prakash, Anand (KOC)
The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing from the Minagish formation in Kuwait and the Divided Zone. The reservoir has been produced intermittently since the 1960s under natural depletion. A powered water-flood is currently being planned. The pressure performance of the reservoir has proved hard to explain without invoking communication with other reservoirs. Such communication could be either with other reservoirs through the regional aquifer of through faults to other reservoirs in the Greater Burgan field. Recent pressures are close to the bubble point.
A coarse simulation model of the nearby fields and the regional aquifer was constructed based on data from the fields and regional geological understanding. This model could be history matched to allow all regional pressure data to be broadly matched, a result which supports the view that communication is through the regional aquifer. Using this model to predict future pressure performance suggested that injecting at rates that exceeded voidage replacement by about 50 Mbd could keep reservoir pressure above bubble point. It was recognized that the process of history matching performance was non-unique. This is a particular concern in the context of this study because the model inputs that were varied in the history matching process included aquifer data that was very poorly constrained. To address this problem multiple history matched models were created using an assisted history matching tool. Using prediction results from the range of models has increased our confidence that a modest degree of over-injection can help maintain reservoir pressure.
This paper demonstrates the utility of computer assisted history match tools in allowing an assessment of uncertainty in a case where non-uniqueness was a particular problem. It also emphasizes the importance of understanding aquifer communication when relatively closely spaced fields are being developed.
Arukhe, James Ohioma I (Saudi Aramco) | Al Dhufairi, Mubarak (Saudi Aramco) | Ghamdi, Saleh (Saudi Aramco) | Duthie, Laurie (Saudi Aramco) | Elsherif, Tamer Ahmed (Schlumberger Middle East SA.) | Ahmed, Danish (Schlumberger Middle East SA.)
Two new records exist in one of current world's largest oil increment field development projects in Saudi Arabia. The records set while achieving a well's intervention objectives include; 1. Attaining the deepest coiled tubing (CT) reach for rigless well intervention at 29,897 ft (9.11 km) measured depth in an extended reach open hole horizontal power injector well using a CT tractor and; 2. The first application of real time logging enabled through a wired motor head assembly via the tractor. The intervention objectives were to acid stimulate an open hole completed relatively deep in the reservoir with total depth of 29,897 feet and open hole length of 6,697 feet utilizing 2" CT with open hole tractor, to perform injectivity / falloff test, and to conduct real time logging for evaluating the reservoir's injectivity profile.
The paper examines several challenges that engineers and operators encountered during intervention in this well. A partially sealing high viscosity tar layer exists between the overlaying oil column and underlying aquifer. Operationally, the challenge was to overcome obstructions arising from tar accumulation during the well intervention. This challenge was overcome by the use of a solvent and the well was successfully acidized with the aid of the CT-tractor. The other concern was the tractor integrity while large amount of acid is pumped and the extended exposure time of tractor to acid. The tractor successfully handled huge amounts of corrosive fluids in a sour environment while providing the required pulling force to reach the total depth of the well to set the intervention record for tractor reach without adverse effects on the integrity of its O-rings, seals, and mechanical parts. In addition to organic deposits, azimuth changes in the well added to well entry challenges as a result of changes in hole inclination, doglegs, and azimuth. The application of real time informed decisions was critical in overcoming all the challenges, optimizing stimulation design, and yielding a notable and consistent injectivity increase with evidence of extended life and a true reflection of deep penetration into the damage zone. The successful re-entry will benefit industry operators confronting similar intervention challenges.
An extensive study of the field and its predominant drive mechanism revealed that production and simultaneous peripheral matrix water injection is the preferred depletion strategy. Extended reach wells and relatively complicated trajectories typically characterize the powered water injectors drilled for reservoir pressure maintenance. The injectors will support oil production from one of the largest field developments in the history of Saudi Aramco in the M field. The field development consists of 27 artificial islands linked by 41 kilometers of Causeway spanning the Arabian Gulf Sea. The blend of onshore, offshore, causeway and artificial island construction concept was the optimal field development option for the field because it results in only 30% offshore development and 70% onshore development. The chosen concept for the field development requires water injection wells to provide peripheral matrix water injection as pressure maintenance strategy to support oil production. A tar mat zone characterizes the field. About 65% of the powered water injection wells have lengths greater than 17,000 feet, beyond the normal reach of coiled tubing.
Padhy, Girija Shankar (Kuwait Oil Company) | Al-Anezi, Khalaf K. (Kuwait Oil Company) | Latif, Ahmad Abdel (Kuwait Oil Company) | Al-Saqran, Fawaz Salem (Halliburton Energy Services Group) | Vasquez, Rafael B. | Thakuria, Abhijit
The Complex pore geometry of carbonate rocks pose challenges in the formation evaluation, production planning and reservoir simulation. Various diagenetic processes, including solution activities causes lateral and vertical heterogeneities in the formation. There exist two main pore networks in the carbonates which controls the petrophysical and productive characteristics, such as, the interparticle pore network (mainly matrix porosity) and secondary pore network (comprising of vuggy pores as well as fractures). The Minagish Oolite reservoir under this current study is no different and hence warrants a clear understanding of the heterogeneity in the reservoir in order to plan a better completion strategy.
In view of this, a study was carried out in one of the wells integrating conventional well log data, Images logs, NMR logs, Sonic logs, Pressure tests and Core to decide right interval to perforate out of the available zones of interests. Conventional logs are unable to address the geological complexity posed by the reservoir. The different textural elements coexisting in the reservoir (the different pore sizes and their distribution) is identified and captured from image logs and NMR. Integration of NMR and borehole image data allowed us to partition the porosity according to pore sizes and compute continuous permeability which was then calibrated to the mobility obtained from Wireline formation testers, core permeability. This permeability measurement was also supplemented with permeability computed from Stoneley wave energy. NMR results also indicated presence of minor bitumen/very heavy hydrocarbon in certain zones which is further validated with visual observation of cores under UV light. Later the permeability results were calibrated with Core permeability and helped to conclude on the presence of heavier hydrocarbons. The integrated analysis allowed us to identify the best flow units over the entire interval and there by optimizing the completion strategy.
The Minagish Field in Kuwait was discovered in 1959 and is located in the southwestern part of Kuwait. It contains several reservoir intervals in its stratigraphic column varying from early Jurassic to late Cretaceous. The Minagish Formation belongs to the lower part of the Thamama Group. The Minagish Formation is a carbonate succession that is classically decomposed in three formation members: Upper, Middle and Lower Minagish. Their depositional setting is under a transgressive system tract regime in a proximal to distal outer ramp to basinal setting and comprises wackestone, packestone and argillaceous rich mudstone with shale interbeds (Davies et.al., 2000). The current study focuses on the Middle Minagish member which mainly is comprised of wackestone, packestone with rare mudstone deposited in a proximal to distal outer ramp environment. The equivalent of this member in the onshore is represented by oolitic grainstone facies having excellent porosity and permeability. The Minagish Oolite occurs in the middle member of the Minagish formation and is the main producing unit. Intense micritization has generated high proportions of microporosity, and it is the distribution of these micropores which mostly influences permeability and hence creating heterogeneity in this carbonate.
Arasu, Raju T. (Kuwait Oil Company) | Nath, Prabir K. (Kuwait Oil Company) | Khan, Badruzzaman (Kuwait Oil Company) | Ebrahim, Maitham (Kuwait Oil Company) | Rahaman, Mafizar (Kuwait Oil Company) | Bader, Sara (Kuwait Oil Company) | Abu-Ghneej, Ali Faleh Naser (Kuwait Oil Company)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154387, "A New Methodology for Stimulation of a High-Water-Cut Horizontal Oil Well Through the Combination of a Smart-Chemical System With Real- Time Temperature Sensing: A Case Study of South Umm Gudair Field, PZ Kuwait," by A. Al-Najim and A. Zahedi, Chevron; T. Al-Khonaini and A.I. Al-Sharqawi, Kuwait Gulf Oil; and P.M.J. Tardy, SPE, A.R. Adil, SPE, I. Nugraha, P. Ramondenc, SPE, and F.S. Al-Hadyani, Schlumberger, prepared for the 2012 SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, The Woodlands, Texas, 27-28 March. The paper has not been peer reviewed.