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Collaborating Authors
Production and Well Operations
Unique Process and Tool Provides Better Acid Stimulation and Better Production Results
Al-Saqabi, Mishari (Kuwait Oil Company) | Gazi, Naz (Kuwait Oil Company) | Vishwanath, Chimmalgi (Kuwait Oil Company) | Al Bahrani, Hasan (Kuwait Oil Company) | Turkey, Naween (Kuwait Oil Company) | Abdul-Razaq, Eman (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Bouland, Ali (Kuwait Oil Company) | Surjaatmadja, Jim B. (Halliburton) | Al Hamad, Abdulla M. (Halliburton) | Brand, Shannon (Halliburton)
Abstract There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point" delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations. Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures. This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
- North America > United States (0.94)
- Asia > Middle East > Kuwait (0.30)
- Well Completion > Acidizing (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Well Drilling > Drilling Operations > Directional drilling (0.55)
- (3 more...)
Abstract 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.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Field Treatment to Stimulate a Deep, Sour, Tight Gas Well using a New, Low Corrosive and Environmentally Friendly Fluid
Nasr-El-Din, H. A. (Texas A&M University) | de Wolf, C. A. (AkzoNobel) | Stanitzek, T.. (AkzoNobel) | Alex, A.. (AkzoNobel) | Gerdes, S.. (Fangmann Energy Services) | Lummer, N. R. (Fangmann Energy Services)
Abstract Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars. Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples. The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
- North America > United States > Texas (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well Intervention (1.00)
- (3 more...)
Abstract 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.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (0.71)
- Well Completion (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (0.88)
Abstract The North Kuwait Jurassic Gas (NKJG) reservoirs are currently under development by KOC. The fractured carbonate reservoirs contain gas condensate and volatile oil at pressures up to 11,500 psi with 2.9% H2S and 1.5% CO2. Currently around 20 active wells are producing to an Early Production Facility (EPF-50) that falls short of achieving the desired capacity and capability to handle production efficiently. To understand wells and field performance, an integrated system model comprising of wells, flow line and gathering system separator network was created. The setting up a model and its use is an integral subset of WRFM (Wells, Reservoir and Facilities Management) process that is essential for effectively managing the current asset and for further field development. The application of the model is to be an enabler for wider implementation of the WRFM process in KOC and a tool to meet the following objectives: It should closely match the EPF-50 throughput It should identify problem wells It should identify well intervention and data gathering opportunities It should be a tool for training engineers on nodal analysis and WRFM It can be used for back allocation It could be used to benchmark against any existing models The model has shown close approximation with field metered production and is already achieving many of its desired objectives. This paper describes the use of integrated nodal analysis model to generate data gathering and well intervention opportunities not only to operate the facilities efficiently but understand well and reservoir behavior for input to full field development plan.
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Sedimentary Geology > Depositional Environment (0.47)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (4 more...)
Continuous Solvent Flush Approach for Asphaltene Precipitations in a Kuwaiti Reservoir: Phase I - An Experimental Solvent Screening
Rashed, Abeer M. (Kuwait Institute for Scientific Research) | Ghloum, Ebtisam F. (Kuwait Institute for Scientific Research) | Al-Matrook, Mohammad F. (Kuwait Institute for Scientific Research) | Oskui, Gh. Reza (Kuwait Institute for Scientific Research) | Mali, P.. (Kuwait Oil Company) | Telang, M.. (Kuwait Oil Company) | Al-Jasmi, Ahmad (Kuwait Oil Company)
Abstract Asphaltene deposition problems in Kuwait have become a serious issue in a number of reservoirs during primary production in different fields, resulting in a severe detrimental effect on the economics of oil recovery. Hence, one of the mitigation approaches in the field is using remedial solvent treatments, such as Xylene or Toluene, which is very costly and harmful to the environment. Kuwait Oil Company (KOC) is planning to produce from asphaltinic Marrat wells that have been shut down due to low bottom-hole pressure (BHP), by artificial lifting technique using an Electric Submersible Pump (ESP) supported with continuous chemical injection, as a pilot. The main objective of this study was to investigate in the lab the effectiveness of various concentrations of toluene/diesel (T/D) mixtures on Marrat reservoir fluid in order to mitigate asphaltene deposition problem during the actual pilot implementation. Preliminary screening tests were conducted on the surface oil sample using Solid Detection System (SDS) "laser technique" to determine the optimum dose of the T/D mixture ratio. The results showed that pure diesel accelerated the asphaltene precipitation; however, mixing T/D inhibited the precipitation process. Series of pressure depletion tests was then conducted on live oil, single phase samples, to determine the Asphaltene Onset Pressure (AOP) with and without adding various ration of T/D solvents at different temperatures from reservoir to surface conditions. The results revealed that using 15% (by volume of oil) from the (50T:50D) mixture reduced the AOP close to the bubble point pressure. Furthermore, the amount of the precipitated asphaltene was physically quantified using a bulk filtration technique. It was observed that, based on blank sample, the wt% of the precipitated asphaltene was minimized at the AOP and maximized at the bubble point. However, using the recommended mixture of 50T/50D, the amount of asphaltene that precipitated was almost negligible. Therefore, from a health, safety, and economic point of view, this study recommends using a low dose of 7.5% (by volume of oil) from toluene mixture with diesel (50%:50%) rather than using pure toluene to prevent the precipitation.
- Asia > Middle East > Kuwait (1.00)
- North America > United States > Texas (0.69)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Abstract 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.
- North America > United States > Texas (1.00)
- Asia > Middle East > Kuwait (0.88)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.34)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (40 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Borehole imaging and wellbore seismic (1.00)
Abstract Oilfield produced water accounts for 98% of all waste generated in oil and gas exploration and processing. This process water may contain up to 1000 ppm total oil and grease, which must be treated prior to discharge. A novel inorganic adsorbent was designed to have high affinity towards such organics. Lab scale evaluations of this adsorbent on production effluents obtained from an onshore site consistently yields TOG removal > 96%. This was found to be a significant improvement over the chemically assisted DAF at 74% in similar lab scale evaluations. This novel technology has the potential to provide a substancial reduction in capital and operating costs for water treatment.
- South America > Brazil (0.29)
- North America > United States (0.29)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Heavy Oil and Tar Mat Characterization Within a Single Oil Column Utilizing Novel Asphaltene Science
Seifert, Douglas J. (Saudi Aramco) | Qureshi, Ahmed (Schlumberger) | Zeybek, Murat (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
ABSTRACT A Jurassic oil field in Saudi Arabia is characterized by black oil in the crest, with heavy oil underneath and all underlain by a tar mat at the oil-water contact (OWC). The viscosities in the black oil section of the column are similar throughout the field and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large, continuous increase in asphaltene content with increasing depth extending to the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. A simple new formalism, the Flory-Huggins-Zuo (FHZ) Equation of State (EoS) incorporating the Yen-Mullins model of asphaltene nanoscience, is shown to account for the asphaltene content variation in the mobile heavy oil section. Detailed analysis of the tar mat shows significant nonmonotonic content of asphaltenes with depth, differing from that of the heavy oil. While the general concept of asphaltene gravitational accumulation to form the tar mat does apply, other complexities preclude simple monotonic behavior. Indeed, within small vertical distances (5 ft) the asphaltene content can decrease by 20% absolute with depth. These complexities likely involve a phase transition when the asphaltene concentration exceeds 35%. Traditional thermodynamic models of heavy oils and asphaltene gradients are known to fail dramatically. Many have ascribed this failure to some sort of chemical variation of asphaltenes with depth; the idea being that if the models fail it must be due to the asphaltenes. Our new simple formalism shows that thermodynamic modeling of heavy oil and asphaltene gradients can be successful. Our simple model demands that the asphaltenes are the same, top to bottom. The analysis of the sulfur chemistry of these asphaltenes by X-ray spectroscopy at the synchrotron at the Argonne National Laboratory shows that there is almost no variation of the sulfur through the hydrocarbon column. Sulfur is one of the most sensitive elements in asphaltenes to demark variation. Likewise, saturates, araomatics, resins and asphaltenes (SARA); measurements also support the application of this new asphaltene formalism. Consequently, the asphaltenes are very similar, and our new FHZ EoS with the Yen-Mullins formalism properly accounts for heavy oil and asphaltene gradients.
- North America > United States (0.94)
- Asia > Middle East > Saudi Arabia (0.48)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Unconventional Use of Production Logging Technology
Chaudhary, S.. (ONGC Limited) | Murty, M. S. (ONGC Limited) | Bora, S.. (ONGC Limited) | Chandra, Y.. (ONGC Limited) | Singh, P. P. (ONGC Limited) | Pandey, R. K. (ONGC Limited) | Bhatt, U. C. (ONGC Limited) | Verma, V.. (Schlumberger) | Ogra, K.. (Schlumberger) | Pandey, A.. (Schlumberger) | Gupta, S.. (Schlumberger) | Sinha, R.. (Schlumberger)
Abstract Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.