Mendoza, Alberto X. (ExxonMobil Neftegas) | Gaillot, Philippe (ExxonMobil Exploration Company) | Yin, Hezhu (ExxonMobil Abu Dhabi Offshore Petroleum Company) | Nicosia, Wayne (ExxonMobil Upstream Research Company) | Guo, Pingjun (Exxon Mobil Corporation) | Mardon, Duncan (ExxonMobil Upstream Research Company) | Passey, Quinn R. (ExxonMobil Upstream Research Co.) | Wertanen, Scott R. (ExxonMobil Exploration & Production Surumana) | Zhou, JinJuan (ExxonMobil Upstream Research Company) | Fitz, Dale Edward (ExxonMobil Upstream Research Co.)
Over last several years, the ability to perform accurate, quantitative formation evaluation in high-angle and horizontal (HA/HZ) wells has been increasingly recognized as a high priority, unsatisfied need within the formation evaluation (FE) community. The industry has realized that the ability to drill extended reach wells has surpassed the ability to evaluate them. Well logs are often underutilized for geologic modeling and assessment applications due to lack of confidence in petrophysical analysis results.
In this paper, we introduce a state-of-art formation evaluation toolkit specifically developed for quantitative interpretation of high angle and horizontal well logs. Starting with wellbore images and standard triple-combo field logs, the workflow consists of: 1) three-dimensional (3D) and two-dimensional (2D) display modules for well path, wellbore images logs, scalar logs and dips to quality control (QC) the data; 2) a comprehensive image analysis module combined with log analysis to build a 3D geometrical earth model; 3) a depth coherence processing (DCP) module to effectively correct recorded borehole images of different logging tool sensors with different depths of investigation (DOI) back to borehole size (BS); 4) a 3D joint inversion module to accurately model and interpret gamma ray (GR), neutron, density, and resistivity logs, to build a common petrophysical earth model; and 5) an output module in which the common earth model is populated with bedding geometries and petrophysical property distributions.
The advanced formation evaluation toolkit described in this paper enables geoscientists to realize much more value than ever before from high-angle and horizontal well data, especially in thinly bedded reservoirs. The detailed description of the internal architecture and lateral petrophysical characterization of the reservoirs are essential for understanding stratigraphy and conditioning geological models. The improved estimations of the petrophysical properties yield more accurate estimates of reserves in place.
In April 2010 we were reminded that Drilling operations are amongst the most hazardous in the world, having the potential for Major Incidents, with the Deepwater Horizon rig fire and explosion. This incident resulted in 11 lives being lost, almost 5,000,000 million barrels of oil being spilt into the Gulf of Mexico over an 87 day period and significant financial loss for bp. This Major Incident also served to remind us that while traditional "Personal Safety?? programs are important to achieve safe drilling operations, these alone cannot effectively manage Major Incident Hazards. E&P Operations can learn valuable lessons from the Process Industry in this regard.
This paper looks at how "Process Safety Management?? implementation, aimed at reducing the potential for Major Incidents, has commenced at an onshore E&P operation. It also discusses the challenges of integrating the culture of Process Safety into existing company culture for operations involving over 60 land rigs comprising both local and international Drilling Contractors and Service Companies.
Process Safety Management system is used to describe those parts of an organisation's management system intended to prevent major incidents arising out of the production, storage and handling of dangerous substances (UK HSE, 2012). It addresses the potential release of these substances caused by:
• Mechanical Failures
• Process Upsets
• Procedures/Human Error
Kuwait Oil Company (KOC) is a subsidiary of Kuwait Petroleum Corporation (KPC), and is involved in the exploration and production of hydrocarbons on land in the state of Kuwait. Existing production is approximately 2.9 mmbopd, with future production targeted at 3.65mmbopd by 2020.
The Exploration and Production (E&PD) Directorate is involved in identifying reserves, drilling new wells and servicing existing wells. It consists of 8 Groups as shown below, and is headed by a Deputy Managing Director (DMD). As most of the PSM challenges in E&PD Directorate lie with Drilling and Service Company operations, the primary focus of this paper will be in these areas.
Cinar, Yildiray (The University of New South Wales) | Arns, Christoph (The University of New South Wales) | Dehghan Khalili, Ahmad (The University of New South Wales) | Yanici, Sefer (The University of New South Wales)
Resistivity measurements play a key role in hydrocarbon in place calculations for oil and gas reservoirs. They are a direct indi-cator of fluid saturation and connected pore space available in the formation. Carbonate rocks, which host around half of the world's hydrocarbons, exhibit a wide range of porosities with scales spanning from nanometres to centimetres. The often sig-nificant amount of microporosity displayed by Carbonate rocks emphasizes the necessity of an adequate characterization of their micro-features and their contribution to hydrocarbon in place. In this paper we examine upscaling methods to probe for-mation factor of a fully saturated carbonate sample using an X-ray CT based numerical approach and compare to experimental measurements.
Three-dimensional high-resolution X-ray CT enables the numerical calculation of petrophysical properties of interest at the pore scale with resolutions down to a few microns per voxel. For more complex and heterogeneous samples however, a direct calculation of petrophysical properties is not feasible, since the required resolution and a sufficient field of view cannot be obtained simultaneously. Thus an integration of measurements at different scale is required. In this study a carbonate sample of 38mm in diameter is first scanned using the X-ray CT method with a resolution of 26µm. After accompanying experimental measurements on the full plug, four 5mm plugs were drilled vertically from this sample and X-ray CT images of these plugs acquired at resolutions down to 2.74 µm. We calculate the porosity of the sample (macro- and micro-porosities) using the phase separation methods and then predict the formation factor of the sample at several scales using a Laplace solver. The formation factor is calculated by using a general value of m=2 as cementation factor for intermediate porosity voxels. We compare to experimental measurements of formation factor and porosity both at the small plug and full plug scale and find good agreement.
To assess the degree of uncertainty of the numerical estimate, we probe the extent of heterogeneity by investigating the size of a representative elementary volume (REV) for formation factor. We find that for the considered heterogeneous carbonate sam-ple, formation factor varies considerably over intervals less than a centimetre. Our results show that this variation could be explained by different cementation exponents applied at the micro-voxel scale, with the exemption of one plug, for which the cementation exponent would have to be unreasonably low. These cementation factors are derived by direct comparison be-tween numerical simulation and experiment. We conclude that for one plug an error in experimental measurement might have occurred. The numerical approach presented here therefore aids in quality control. Excluding this plug in the upscaling proce-dure improves the agreement with the experimental result for the whole core while still underestimating formation factor. Al-lowing for a constant m=2 in the simulation at the small scale and using directly the resulting relationship between porosity and formation factor in the upscaling process leads to an overestimation of formation factor.
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 directional drilling companies in oil industry usually provide well placement services using proprietary geosteering software that utilize conventional Logging-While-Drilling (LWD) data. Usually online access to the recorded logs is available to end users, but often very limited capability exists within the oil companies to test geosteering interpretations and advise. Present paper shares the case studies of some wells in which Gas-While-Drilling (GWD) data was used in conjunction with the LWD data for well placement. Furthermore, the Geosteering Module of a third party 3D Geological modeling software was used independently within the West Kuwait Fields Development group of KOC for well placement.
Well D-08 was drilled as vertical producer in a West Kuwait Marrat carbonate reservoir, produced economic quantities of oil during initial testing, but it started cutting high amount of water due to the effect of a fault. Therefore, the well was re-entered and sidetracked at a high angle, away from the fault. Similarly, the U-73 vertical well which encountered poor reservoir facies on flank of the field, was re-entered for productivity enhancement into a thin porous reservoir layer as horizontal sidetrack towards the crest. Both these wells were monitored and geosteered in near real-time using a geosteering software module which combines the overall structural framework provided by 3D geological model, along with the well log responses characteristics from offset wells, to produce a detailed pre-drill model for Geosteering. This is achieved by forward modeling to predict changes in log characters along the planned wellbore profile. The results are displayed both in vertical and measured depth domains along a 2D curtain section with formation tops parallel to the planned well azimuth.
In addition to the conventional LWD logs, the GWD logs generated from advanced gas analysis of the drilling mud were used for geosteering during drilling well D-08 and U-73 re-entry sidetrack wells. The LWD and GWD based geosteering were done independent of each other to test the efficacy of GWD method. Geosteering software and advanced mud gas data have been paired for high angle and horizontal well placement for the first time in Kuwait which successfully guided the well trajectory while drilling.
Fan, Zifei (Petrochina Research Institute of Petroleum Exploration and Development) | Yang, Xuanyu (China University of Petroleum) | Xue, Xia (China National Oil and Gas Exploration and Development Corporation) | Xu, An Zhu (PetroChina E&P Co) | He, Ling (Petrochina Research Institute of Petroleum Exploration and Development) | Zhao, Lun (Petrochina Research Institute of Petroleum Exploration and Development) | Mu, Longxin (Petrochina Research Institute of Petroleum Exploration and Development)
The well patterns and pattern types of well placement issue in a productive formation is an important aspect of the effective field development. The problem solution is impossible on the intuitive level due to the reservoir inhomogeneity. At present the well pattern is accepted to be located basing on the famous criteria, specialist experience and hydrodynamical simulation on a reservoir model. The designer should analyze many field development variants with different well spacing during limited time interval. The adjustment of large-scale multiwell field-development projects is challenging because the number of adjustment variables and the size of the search space can become excessive. This difficulty can be circumvented by considering well patterns and then optimizing parameters associated with pattern type and geometry. In this paper, we introduce a new framework for accomplishing this type of adjustment for vertical two or three reservoirs.The development of vertical multiple reservoirs were usually by a separate well pattern for every reservoir, or through reservoir-by-reservoir from bottom to top by only one well pattern. A separate well pattern for every reservoir requires drilling many more wells and higher investment costs, while development through reservoir-by-reservoir from bottom to top by one well pattern made oil recovery rate and development efficiency very low and uneconomic. Consideration on fully developing every reservoir well efficiently, firstly, an inverted-nine well pattern was designed for every reservoir and the well space was L (L was defined as an optimal well space for respective reservoir) and the distance between adjacent well patterns was L. Secondly, all wells were drilled to the bottom of the lowest reservoir. Thirdly, when average water-cut of producers in every two well patterns was greater than 80%, the two well patterns interchanged reservoirs. Finally, when all reservoir interchange was completed, every reservoir was developed by the new equivalent infilled well pattern with well space of L. The adjustment strategy made the required number of drilling wells in the whole field can be reduced by 50% and achieved better development effect. This strategy was put into practice on North Buzachi oil field in Kazakhstan and average oil rate of single well was increased by 20%, oil recovery rate has an increment by 12 percent, the recovery factor was increased by 6.7%, economic profit is 1.8 times that of one separate well pattern for every reservoir, the effect was perfect. This work analyzed the performance of this new strategy of well pattern design and adjustment to effectively develop vertical multiple series of reservoirs and the methods to determine the reasonable time of two well patterns interchanging reservoirs through simulation study and current application effects.
Thread compound "dope?? in the vernacular, has been used routinely in assembling joints of casing and tubing. The practice in almost universal application in the oil and gas industry involves the manual application of the lubricant in a fashion that is rudimentary, non-systematic and unquantifiable. There is evidence presented in this paper that damage to the near-well zone and other unpleasant events may be associated with the thread compound.
This paper presents the results of both laboratory and field investigations quantifying the effects of the dope on near-well damage. During the assembly of tubing and casing a portion of the thread compound is exuded inside and outside the connection and gets access to the well fluids through the tubing and annular space. Studies presented here show that the dope forms a suspension which penetrates and damages the formation. The studies used standard fluid circulation velocities during typical completion operations.
To characterize and quantify the problem, core samples from the El Tordillo field, with different permeabilities were used. The samples were subjected to the circulation of the suspension created by the thread compound and the completion fluid, measuring the change in the core permeability. The work simulated the well conditions during water injection for water injection wells and during acid treatments for producer wells. A significant reduction in permeability, manifested by a fast and a very large increase in pressure, was measured, at the front face of the core sample. The same measurements showed a far smaller impact in the core body suggesting very minor penetration of dope particles.
This paper describes the laboratory and field work, with description of the test protocols, well conditions and laboratory emulation of field conditions that were used.
Al-Kuait, A.M.S. (Saudi Aramco) | Al-yateem, Karam Sami (ARAMCO Services Company) | Olivares, Tulio (Halliburton) | Zubail, Makki A. (Saudi Aramco) | El Bialy, Moustafa (Halliburton) | Ezell, Ryan G. (Halliburton) | Maghrabi, Shadaab (Halliburton)
Safaniya is one of largest offshore oil fields located north of Dhahran in Saudi Arabia. It is 50 km by 15 km in size and began production in 1956. Lately, a few wells drilled in this field showed reservoir damage where the production dropped or the well had no flow. Workover operations were performed on six wells and two new wells were drilled. For all eight wells, 6?-in. laterals were drilled through the reservoirs with an engineered invert emulsion drilling fluid (RDF). The RDF design was controlled to ensure an acid-soluble, thin, external filter cake with no fines invasion. The vulnerability of the filter cake to be attacked by the acid was fundamental to this RDF design. A delayed filter cake breaker fluid was then designed for use on the 6?-in. laterals; this fluid consisted of an organic acid precursor (OAP) and a water wetting additive. The OAP released acid in a delayed manner, whereas the water wetting additive made the oil-based filter cake water wet, to make it vulnerable to acid attack. With this approach, the filter cake was removed uniformly in all subject laterals across the reservoir. The production data on the eight wells treated with the OAP show an improved oil production rate of more than 4,000 B/D for six of the eight wells, which exceeds the key performance indicator (KPI) set for the laterals. In previous years from 2005-10, the six workover wells showed, on average, very low oil production rates (OPR) comparatively. In addition, after the OAP treatment, these six wells show higher well flow head pressures than in 2005-10. The water cut percentage on these laterals was 0 or less than 1, compared to 2005-10, when the water cut percentage varied from 8% to 50% for these workover wells. This paper discusses the workover operation of the six wells and the drilling and delayed stimulation treatment on two new wells in the Safaniya field, including laboratory evaluation, field application and production data.
Influenced by the success of shale gas production worldwide and to meet requirements for clean energy supply, a multidisciplinary team of petroleum specialists was established in Saudi Aramco. Meeting the growing requirement in industrial consumption and especially electricity production is driving force for developing unconventional gas reserves. "The initial focus is in the northwest and in the area of Ghawar, where gas infrastructure exists. Initial knowledge building from similar plays in North America is being supplemented with internal technical studies and research programs to help solve geological and engineering challenges unique to Saudi Arabia and to locate specific wells planned for 2011. The company is innovatively combining knowledge and research to maximize gas reserves and production from conventional and unconventional resources in order to meet growing domestic demand.?? 
During years 2010 - 2011 major international petroleum industry players - Schlumberger, Halliburton and Baker Hughes - were invited to share their experience in a series of workshops held in Dhahran. Exchange of expert ideas developed into appreciation of complexity of the shale gas reservoir and helped to identify the scope of work for the first Silurian Qusaiba shale gas well. The SHALE-1 well was drilled in 2007 as a gas exploration well. Recent drilling and geophysical data obtained in the well were beneficial for detailed sidetrack and fracture stimulation design.
The Multidisciplinary Saudi Aramco - Halliburton SHALE-1 task group was established and positioned in Dhahran. This allowed them to have regular face-to-face meetings and improve the most critical criteria of any new venture - communication. The draft work plan was developed 8 months before actual operations commenced on the well site. Thorough examination of the draft work plan progressed to the final work plan with a number of improvements. For example, "R?? Nipples were dropped from the monobore 4-1/2?? completion string. The Frac Stimulation design was fine-tuned, involving expertise from Saudi Aramco and Halliburton. The Complete Well on Paper exercise involved over 25 specialists from both sides and helped to rectify remaining completion/stimulation design issues, and put everyone on the same page in terms of the work program. Well site operations commenced in May 2011; the well was successfully re-entered and window cut in 7?? liner. An S-shaped 5-7/8?? hole was drilled in the direction of minimum horizontal stresses, to the required depth in Qusaiba Shale with a maximum DLS of 4°. The well was completed with 4-1/2?? cemented liner and monobore 4-1/2?? string to surface. The Hot Qusaiba interval was perforated; frac stimulated with mixed results and successfully flowed. A temporary isolation FasDrill plug was set above the perforation interval. The Warm Qusaiba interval was perforated; successfully frac stimulated and flowed with mixed results. Finally, the FasDrill plug was drilled out with CTU and both intervals flowed and required production log runs.
All targets set for the SHALE-1 re-entry well were successfully achieved and the well was suspended for future utilization as an observation well.
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.