At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
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.
Al-Kandary, Ahmad (Kuwait Oil Company) | Al-Fares, Abdulaziz (Kuwait Oil Company) | Mulyono, Rinaldi (Kuwait Oil Company) | Ammar, Nada Mohammed (Kuwait Oil Company) | Al naeimi, Reem (Baker Hughes) | Hussain, Riyasat (Kuwait Oil Company) | Perumalla, Satya (Baker Hughes)
Role of geomechanics is becoming increasingly important with maturing of conventional reservoirs due to its implications in drilling, completion and production issues. Exploration and development of unconventional reservoirs involve maximizing the reservoir contact and hydraulic fracturing both of which are heavily dependent on geomechanical architecture of the reservoirs and thus require application of geomechanical concepts from the very beginning.
To support the unconventional exploration and conventional reservoir development in Kuwait, country-wide in-situ stress mapping exercise has been carried out in nine fields of Northern Kuwait. Stringent customized quality control measures were put in place to evaluate stress orientation. Cretaceous and sub-Gotnia Salt Jurassic rocks exhibit distinct patterns of stress orientations and magnitudes. While the variations in stress orientation in the Cretaceous rocks are within a small range (N40°E-N50°E) and consistent across major fault systems, the Jurassic formations exhibit high variability (N20°E-N90°E) with anomalous patterns across faults as well as in the vicinity of fracture corridors. Moreover, the overall stress magnitudes were found to be much higher in the strong Jurassic section compared with the relatively less strong Cretaceous strata. During the analysis, it was also observed that several natural fractures in Jurassic reservoirs appear to be critically stressed with evidences of rotation of breakouts.
Using geomechanical models from a specific field, the effects of in-situ stress, pore pressure and rock properties on formations were evaluated in inducing wellbore instability during drilling operations in a tight gas reservoir. It was found that the most favorable orientation for directional drilling is parallel to the maximum horizontal stress (SHmax) within that field.
The geomechanical study provided inputs not only for wellbore stability during drilling, but also regarding the response of natural fractures to in-situ stresses to become hydraulically conductive (permeable) to act as flow conduits. The fracture model of the field shows that the dominant fracture corridor trend in the field is NNE coinciding with present day in-situ maximum principal stress direction.
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.
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.
Al-salali, Yousef Zaid (Kuwait Oil Company) | Ayyavoo, ManiMaran (Kuwait Oil Company) | Al-ibrahim, Abdullah Reda (Kuwait Oil Company) | Al-Bader, Haifa (Kuwait Oil Company) | Duggirala, Vidya Sagar (Kuwait Oil Company) | Subban, Packirisamy (Kuwait Oil Company)
This paper discusses the outstanding performance achieved in a deep HPHTJurassic formation drilled using Potassium Formate based fluid. This paper alsodescribes methodology adopted for short term testing and stimulation of anexploratory well and finally the field results.
Drilling and completion of deep Jurassic formations in the state of Kuwaitis generally done with Oil Base Mud (OBM) weighted with Barite. Duringdrilling, barite causes significant formation damage to the carbonates withnatural fractures and it is essential to stimulate the well to evaluate thereal reservoir potential. Formation damage is usually treated with matrix acidstimulation, however barite does not respond to acid. Kuwait Oil Company (KOC)was in search for an alternative drilling fluid causing relatively lessformation damage and also responds to remedial actions. Potassium Formate brinewith suitable weighting agent to achieve sufficient mud weight around 16ppg wasselected for field trial in one of the exploratory wells. Formate based brineis a high-density Water Base Mud (WBM) which maintains rheological stability athigh temperature and minimizes formation damage.
Last 2,000 feet in 6" hole section of 18,000 feet well was drilled using15.9 ppg Potassium Formate WBM. During short term testing, acid wash alone wassufficient to remove the formation damage and productivity has tripled which isunlikely in case of wells drilled with OBM.
This case study shows how Potassium Formate based mud enhanced theproductivity and reduced the testing time and cost. Based on the successfulfield test results, it is planned to drill future Jurassic deep formation withPotassium Formate based fluids in future.
Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Al- Doheim, Aref (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Ajmi, Saad (Kuwait Oil Company)
Robustness of measurement while drilling (MWD) and logging while drilling (LWD) tools is laboratory-tested and rigorously field-tested for the expected operating and measurement specifications. Such tools have been used in the industry for decades with proven track record of stability. However, a typical tool string deployed as a part of bottom-hole assembly (BHA) has recently failed to withstand the unexpected BH conditions during drilling of the pilot hole using potassium formate mud (KFM), a heavy water based mud. The failure occurred within a deep-fractured calcareous kerogen section (CKS).
The tools had multiple surface communication failures; the first one was resolved as debris was found obstructing the rotor-starter part before drilling the CKS. The second failure occurred in the back-up tools, after drilling into the CKS and remained unexplained throughout drilling with the expectation of BH data recorded on memory. Inspection of the tool components, once the drilling was completed, revealed two major findings: First, some parts of the BHA, specifically the components of the CuBe tool had "vanished??. Secondly, the recovered tool parts had further damage due to corrosion and pitting. In addition, an unexpected color change in metal body parts was observed.
In the paper, the authors explain the unique mystery of tool eating "down-hole ghost??. Similar tools were previously used without an issue at comparable high pressure and temperature conditions and in geological sections alike in Kuwait in drilling with oil-based mud. The service provider's operational experience elsewhere has failed to explain the bizarre outcome, as they had not encountered similar incidents of vanishing tool parts and down-hole color change. The claim was that similar tools were successfully operated in water-based mud drilling including KFM. This claim was confirmed prior to the field execution with metallurgical compatibility tests carried out by the mud supplier.
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.
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 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.