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Results
Improvements of Sampling and Pressure Measurements with a New Wireline Formation Tester Module in Carbonate Reservoirs
Cig, Koksal (Schlumberger Middle East S.A.) | Osunluk, Halil Ibrahim (Schlumberger Middle East S.A.) | Naial, Radwan (ADCO) | Ihab, Tarek Mohamed (ADCO) | Al Baloushi, Ahmed Yahya (ADCO)
Abstract A multilayer hydrocarbon reservoir in Abu Dhabi land is in an appraisal stage before experiencing an extensive field production operation. The hydrocarbon reservoir, having medium to low permeabilities, consists of a number of carbonate layers with their associated oil-water contacts. One of the challenges is to sample hydrocarbons in tighter layers as well as to measure valid reservoir pressures to determine oil-water contacts. While the goal is to accomplish the objectives with wireline formation testers (WFT) in openhole conditions, stationary times during logging are limited due to wellbore conditions. The time limit has been a longstanding challenge in the layers having especially lower permeabilities (<1md). A typical sampling operation involves advanced modules of WFT including a Dual-Packer and an Insitu Fluid Analyzer to identify fluid types and provide downhole compositions with densities. Reservoir pressures are measured generally with Single-Probe modules. The new WFT inlet module is introduced first time in Abu Dhabi across the carbonate formations to accelerate the stationary operations. The new inlet module showed an improvement over a Dual-Packer and a Single-Probe modules in several aspects: Stationary times during sampling are reduced due to very low interval volumes in comparison to a Dual-Packer module and up to 60% faster oil breakthrough times are achieved. Tight zone pressures are measured as fast as a Single-Probe module with lower supercharging effects. Set and retract times are shortened so that a new sampling method of a set-retract-reset is developed without exceeding stationary times. This paper summarizes the recent achievements by reducing risks associated with long stationary times. The field benefits are demonstrated in two separate WFT operations by comparing data qualities and job efficiencies in the same reservoir layers. Results show faster sampling, more accurate pressure and permeability measurements in the carbonate reservoir.
- North America > United States > Texas (0.49)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.45)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Overview (0.34)
Use of Wireline Formation Tester Stress Measurements and Sonic Logs for Improved Geomechanical Model Construction of a Giant Depleted Gas Reservoir in Abu Dhabi Land: A Case Study
Cig, Koksal (Schlumberger Middle East SA.) | Osunluk, Halil Ibrahim (Schlumberger) | Povstyanova, Magdalena (Schlumberger) | Masoud, Rashad (ADCO) | Ammari, Khalid (ADCO)
Abstract Abu Dhabi land has a giant gas field consisted of layered carbonate reservoirs. The long term plan of the field has been to produce the reservoirs with the safest maximum depletion. A detailed geomechanical study was undertaken to identify changing field stresses and to understand the possible reservoir rock collapse mechanisms. The foundation for any 3D geomechanical modeling is 1D Mechanical Earth Model that includes elastic and strength properties, overburden stress, pore pressure and magnitude and direction of horizontal stresses. The input data for 1D modeling is openhole logs (density and compressional and shear sonic logs). Image data, caliper logs, pore pressure and closure and breakdown pressure measurements are necessary to calibrate the models. To improve quality and reliability of the 1D MEMs, Abu Dhabi Company for Onshore Oil Operations (ADCO) requested lab measurements to calibrate elastic and strength rock properties and decided on pore pressure and stress measurements in one of the upcoming wells. Wireline Formation Tester (WFT) technique was selected to provide pore pressure, as well as closure pressure to calibrate magnitude of minimum horizontal stress directly and breakdown pressure to calibrate magnitude of maximum horizontal stress indirectly. Acquired compressional and shear sonic logs allowed building continues properties, pore pressure and stress profiles. Introduction 3D geomechanical modeling was conducted for the interested reservoirs in the Bab field. The main objective of this study was to investigate possibility of formation rock collapse, particularly within severely depleted areas, and associated well collapse and completion integrity damage. This study also aimed at assessing potential geomechanics-related risks due to early depletion (cap rock integrity and fault sealing capacity). Figure 1 shows the general workflow of this study. Firstly, 1D Mechanical Earth Models (MEMs) were constructed using available wireline logs. The measured data was used to calibrate the calculated elastic and strength rock properties, pore pressure and horizontal stress profiles. Drilling reports were analyzed to extract wellbore instability-related events to calibrate the 1D MEMs further. To better capture variation of elastic and strength properties across the reservoir, 1D MEMs were constructed for several wells. Then, a 3D MEM was built based on the static geological model and dynamic reservoir model. 1D MEMs were used to populate the mechanical properties for 3D modeling carried out for the duration of pre-production until present. The results were calibrated against the production data. The calibrated 3D model was then used to perform two-way coupled modeling for future rock behavior in the cap rock and reservoir depletion mechanism.
Abstract Over the past decade low-salinity water flooding has emerged as a viable enhanced oil recovery (EOR) method. Both laboratory tests and field trials have shown that injecting chemically modified water instead of seawater can lead to incremental oil recoveries. Although much research has been conducted, the governing physical and chemical mechanisms for this increase in recovery are not yet agreed upon, but are generally believed to involve some form of interaction between the rock, oil, and brine leading to changes in wettability, oil/water interfacial tension, or both. The relative uncertainty in the physics of the recovery process calls for a carefully staged screening and pilot program before committing to full-field implementation. The EOR MicroPilot* is a single-well piloting technique that enables rapid and inexpensive testing of EOR methods under in-situ downhole conditions. It is a log-inject-log technique conducted with a wireline formation tester (WFT). A small quantity of EOR fluid is injected and the resulting change in oil saturation is then determined based on a set of openhole logs, which are run both before and after the injection. In this paper we investigate the feasibility of a MicroPilot for low-salinity water flooding. Through simulation we show that the changes in oil saturation and salinity are measurable by the openhole logs. We further quantify the conditions under which a low-salinity MicroPilot is feasible in terms of the minimum measurable saturation changes and the contrast in salinity between the injected and resident brines. To assess the accuracy of the numerical solutions, we have conducted grid sensitivity studies as well as comparisons with analytical solutions to simplified 1D problems. The results of this paper are directly applicable to the planning of low-salinity waterflood pilots. The methodology proposed, based on the MicroPilot concept, can reduce piloting costs as well as reduce the time required between laboratory testing and field implementation. Introduction The MicroPilot (Arora et al. 2010) was introduced as an intermediate step in the enhanced oil recovery (EOR) screening process between laboratory testing and traditional multiwell field pilots. The technique works like a downhole laboratory by injecting a small quantity of the EOR fluid and measuring the resulting decrease in residual oil saturation. In this way laboratory results can be validated at downhole conditions, thus reducing the uncertainty associated with subsequent field pilots. The MicroPilot is a log-inject-log technique which can be executed in a matter of hours to days, making it a relatively inexpensive step in the EOR screening process. After the target well is drilled for application of the technique, a suite of wireline openhole logs is run to determine the initial saturations. A formation tester string is then used to inject the EOR fluid, typically 10 to 20 L, through a pencil-sized hole drilled into the side of the wellbore at the target depth. Following injection, the suite of openhole logs is run again to evalutate the effectiveness of the flood by measuring the change in oil saturation and the dimensions of the flood. Injection stations can be selected at multiple depths, which provides the ability to test an EOR method in different zones of the reservoir or test different EOR fluids within a single zone, all within a single job. A schematic of the MicroPilot is shown in Figure 1. Arora et al. (2010) reported on the first EOR MicroPilot which was conducted in a medium heavy-oil sandstone reservoir using a mixture of alkaline, surfactant, and polymer chemicals (ASP) as the EOR fluid. They covered aspects of the job design, execution, and log interpretation. Cherukupalli et al. (2010) presented flow modeling of the first MicroPilot showing that the saturation changes measured by the logs could be successfully matched by a relatively simple model of the ASP process. Finally, Edwards et al. (2011) recently reported on the second application of the technique, which was conducted in a light-oil carbonate reservoir using an alkaline-surfactant mixture as EOR fluid.
- Asia > Middle East (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.45)
- North America > United States > Oklahoma (0.15)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.34)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
Advances in Wireline Conveyed In-situ Reservoir Stress Testing Measurements: Case Studies from the Sultanate of Oman
Cig, Koksal (Schlumberger Middle East SA.) | Al Mandhari, Alyaqdhan Sulaiman (Schlumberger) | Elmsallati, Salem Mohamed (Petroleum Development Oman) | Qobi, Latifa (Petroleum Development Oman)
Abstract In-situ reservoir stress measurements are essential input to a wide variety of the production and injection applications of reservoirs. Most of the reservoirs in this article require water injection to maximize recovery without breaking the matrices unintentionally. In some cases, it is also important to create a controlled fracture growth in a formation unit without breaking bordering barriers or zones. The main purpose of the in-situ reservoir stress testing of the case studies in this article is to calculate the minimum stress to improve the reservoir management plans for well placement, production, injection and fracturing processes. One approach of measuring stresses in many zones is to use the wireline conveyed stress testing tools. The wireline conveyed in-situ reservoir stress testing measurements are frequently performed in the Sultanate of Oman for a wide range of operational and geomechanics applications such as but not limited to:Hydraulic fracturing Fracture growth/containment issues Polymer injection Borehole stability Sand production prediction Stress evolution with depletion, hot and cold injection The stress testing zones vary from tight to high permeable zones as well as shale zones. The complexity and wide variety of the stress testing applications inevitably led modifications and improvements on the wireline conveyed stress testing tools. These improvements mainly are various types of pumps, higher performance dual packers and mandrels, innovative stress testing methods. The latest improvements and methods in stress testing help addressing the broader range of formations (deep and shallow, tight and permeable) in an extensive type of wells from vertical or deviated to horizontal. In this article, the examples of several unique stress testing applications are presented. Shale stress testing with a viscous fluid, horizontal well stress testing, tight and very high permeability formation stress testing, sleeve fracturing stress testing methods are discussed in details. Introduction In-situ stress magnitude and direction measurements in vertical and lateral directions are required in a reservoir for several reasons. These are for hydraulic fracture design, fracture type identification, water and gas injection management, fault activity, wellbore stability, sand production, rock mechanical properties, casing strings design, cap and base rock integrity, subsidence, and gas storage design.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Oman (0.62)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.73)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 9/23a > Tullich Field > Balder Formation (0.99)
- Europe > Norway > North Sea (0.91)
- (2 more...)
Flow Unit Thickness and Permeability Evaluation in Horizontal Wells Using Logging While Drilling and Wireline Formation Tester Transient Data
Cig, Koksal (Schlumberger Middle East SA.) | Ayan, Cosan (Schlumberger) | Mahruqy, Sultan (Petroleum Development Oman) | Al-Shamsi, Khalsa Abullah (Petroleum Development Oman)
Abstract Oil was discovered in a carbonate reservoir which indicated discontinuous and complex geological features. The carbonate field in the Sultanate of Oman is at the early stages of development and reservoir uncertainties are still significant. The uncertain geological features, proximity of possible faults and heterogeneous reservoir properties make horizontal well placement a difficult task. The latest logging while drilling (LWD) technology for well placement was utilized to track the distance to the upper flow unit of the reservoir. It was discovered that the formation was dipping upwards and had separate units. The lower flow unit boundary was uncertain due to the LWD distance detection limit. Flow unit thickness identification became an important task to understand the potential of the reservoir. The objective of this study in the complex reservoir is to present a new way to determine the flow unit thicknesses by utilizing the LWD and wireline formation tester (WFT) interval pressure transient tests (IPTT) data. IPTT tests with a dual inflatable packer in combination with LWD logs resulted in local horizontal and vertical permeabilities and flow unit thicknesses along the horizontal well. Integration of the two distinct logging methods helped accomplish not only the well geometry and local petrophysical properties, but also gave information on large scale properties. The wells were also surveyed with open hole logging tools to obtain sedimentary features, to collect necessary oil samples and to obtain reservoir properties such as faults information, saturations, permeabilities and in-situ rock stresses. Following data acquisition and joint evaluation, an integrated study was conducted for the field development. This paper presents an integrated solution of LWD logs and IPTT data evaluation. The approach had a considerable impact on field development plans and reserve calculations in the new and complex carbonate reservoir. Introduction Reservoir Geology The geology of the reservoir in the study presents a stratigraphic trap in an Upper Shuhaiba carbonate formation sealed by a shale layer above and by argillaceous limestone facies laterally. The reservoir units represent the shoaling and upper slope portion of clinoforms that prograde into the basin. Rudist /stromatoporoid bioherm and reworked facies ranging from fine to coarse grained have been encountered in addition to more common orbitolinid packstones and wackstones. The quality of the reservoir represents a complex relationship between primary depositional facies and subsequent diagenisis in the form of both cementation and leaching (Fig. 1). Obtaining core samples subsequently assists understanding the complexity of the lithology. The thickness and permeability distribution of the reservoir is difficult to foresee without extensive logging and testing. Location and distribution of the reservoir quality facies represent one of the major uncertainties for developing of the reservoir. Formation microresistivity imager logs provide the fracture and facies distribution of the rock textures with the correlation of cores collected (Wang et al. 2008). Seismic data gives some indications of these structures and a recent reprocessing allows partial answers for reservoir units in some areas.
- North America > United States > Texas (0.95)
- Asia > Middle East (0.90)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Logging while drilling (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (4 more...)
Data Acquistion and Formation Evaluation Strategies in Anistrospic, Tight Gas Reservoirs
de Koningh, Hans (Horizon Energy Partners) | Herold, Bernd Heinrich (Schlumberger Logelco, Inc) | Cig, Koksal (Schlumberger Oilfield Srvcs) | Ali, Fahd (Schlumberger) | Mahruqy, Sultan (Petroleum Development Oman) | Johnston, Sean (Schlumberger) | Karavadi, Venkata Narayana Rao (Petroleum Development Oman) | Abd El Moula, Ibrahim (Petroleum Development Oman)
Abstract In a time of declining production and increasing demand, geoscientists are challenged more and more often to develop new techniques and strategies for evaluation and appraisal of increasingly complex and deeper reservoirs. This paper describes the subsurface challenges and how, through optimized data acquisition and application of integrated formation evaluation techniques, tight gas reservoirs have been characterized and the objectives of data acquisition programs have been met. Examples are illustrated with data from three recent wells. The operating environment is very challenging, which affects the decisions for data acquisition. The use of salt-saturated mud systems creates a high resistivity contrast between mud and formation, affecting image and nuclear magnetic resonance data quality. The anisotropy in the stress field results in elliptical boreholes with breakouts. This leads to complex resistivity log responses, which require special corrections and a modeling approach. Furthermore, the data quality of wireline pad tools is compromised. The low-porosity formation affects the accuracy of water saturation calculations and fluid mobility ranges in the sub-md region make fluid sampling and the acquisition of formation pressures a complex task. Often completion decisions have to be based on basic formation evaluation data alone as acquiring pressure data or fluid samples is not possible. Only if borehole effects are sufficiently understood and corrected for can this basic formation evaluation be presented with some confidence. Trend analyses are, however, often more instructive than absolute averages of calculated pay summaries. Resulting porosity and saturation estimates should always be put in context of other well results and alternative data sources like borehole image and mud gas data. Introduction The exploration for deep gas in Oman started after a decision was made to deepen an exploration well targeting an oil reservoir at shallower stratigraphic levels. The Saih Nihayda gas-condensate field was discovered in 1989, followed by Saih Rawl (1990) and Barik (1991). Consequently exploration and development of gas and gas-condensate reservoirs has focused on deep reservoirs in the Haima Group in North Oman's Ghaba and adjacent Afar area (Fig. 1). The fields making up the Kauther cluster where discovered in 2001 and 2002 and are currently being developed. Following success in Ghaba basin exploration efforts have focused on the deeper still Haima formations in the Fahud Salt basin. As the reservoirs are typically relatively thick (~200m) and have low permeability (<0.1md) the developments are based on vertical wells that are stimulated with massive vertical fracs. Formation evaluation is becoming increasingly challenging with increasing depth. Three factors that affect our ability to interpret downhole data are discussed in detail in this article. The first one, an abnormal pressure regime, results in severe borehole breakouts. The second, increasing temperatures with increasing depth, results in reduction of data quality, tool failures and a reduction in available downhole sensors. The third, decreasing porosity with depth, requires high accuracy in sensors to allow correct porosity evaluation as inaccuracy in porosity estimates leads to unacceptable uncertainty in fluid saturation estimates. Combined these three factors result in a difficult logging environment making it increasingly difficult to acquire a good quality data set for formation evaluation.
- Asia > Middle East > Oman > Al Wusta Governorate > Haima (0.45)
- Asia > Middle East > Oman > Ad Dakhiliyah Governorate (0.44)
- Asia > Middle East > Oman > Central Oman (0.34)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.88)
- Asia > Middle East > Oman > Ghaba Salt Basin (0.99)
- Asia > Middle East > Oman > Fahud Salt Basin (0.99)
- Asia > Middle East > Oman > Ad Dakhiliyah Governorate > Ghaba Salt Basin > Saih Nihayda Field (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Abstract Production logging is difficult in complex well designs such as horizontal multilateral (ML) wells with jagged level-two exits. The ML exits can obstruct the access of logging tools due to damage around the milled windows. Once inside a low-flow high-water cut reservoir, the challenge becomes measuring an oil inflow profile in stratified flow. The access issue is worse in sub-hydrostatic wells completed with artificial lift. Horizontal gas lifted wells are easily choked by the presence of coiled tubing (CT). Y-Tools can be deployed in electrical submersible pump (ESP) wells to provide bypass tubing for logging strings necessary to log while pumping, although the system has not been successful in low rate wells due to re-circulation across the dynamic seal in the Y-Tool. This recirculation invalidates the log data and overheats the motor. As in gas lift completions, the low rate ESP completions also suffer rate reduction caused by the presence of CT. This paper describes the methods used to overcome these access and production logging challenges in North Oman. A new tool configuration that comprises a vertical array of mini spinners and fluid type sensors was used to detect a 2% oil hold-up in a stratified flow. It has a surface controlled collapsible spinner cage that makes the tool slick to maneuver around obstructions in the well. This has overcome some of the level 2 bypass problems in ML wells. A temporary ESP and Y-tool upper completion has been used to log a 3-leg ML backbone successfully. To fix the recirculation problem, a modified Y-tool plug was designed to reduce the fluid leakage in the dynamic seal. A variable speed drive (VSD) at surface controlled the ESP motor speed, adjusting the pump rate to compensate for the rate reduction caused by the presence of the CT. Wireline conveyed tractors have overcome some of the choking limitations of CT in gas lifted wells. Openhole completions remain a challenge. Introduction There are numerous challenges for the well and reservoir management engineer who wants to acquire production logs (PLT) in brown fields. Often the wells were not constructed with intervention in mind, and as the water cut gets high it becomes a challenge to detect the oil at all. Drilling methods and the understanding of multiphase fluid dynamics such as stratified flow have improved since the first horizontal wells were drilled in the early 1990s. Now we know it is best to avoid undulations in the trajectory of these wells to minimize water sumps and gas pockets, and to provide a straighter well for deeper reach with CT. Also, fluid entries can be masked by the hold up changes created by these deviation changes. Nowadays, several technologies have enabled holes to be drilled much closer to true horizontal, for example near bit continuous inclination and rotary steerable systems. However it is the old horizontal wells with undulations that have the high water cuts today, and are often the focus of well and reservoir management. Multilateral wells were the next step in maximizing contact with the reservoir from one wellhead. Recent multilateral well designs may have fluid control devices on each lateral, with a production test of each leg possible from surface. However the early designs only have open hole branches, or milled casing exits into open hole laterals. In these wells even logging the backbone can be a challenge. Openhole completions present another set of difficulties, especially if the well is not cleaned up at the time of logging as in Figure 1. The most difficult wells are long horizontal holes drilled in sub-hydrostatic reservoirs with a high water cut. These wells present significant access problems when there is insufficient fluid viscosity and velocity to circulate residual mudcake and shale debris to surface. The shale debris is released from water exposure or stress related washouts. This creates challenges for any logging device that has external moving parts such as spinners. Reservoir pressure maintenance with water flooding in brown fields has led to an increased requirement for artificial lift due to high water production. As these wells become more sub hydrostatic gas lift is no longer enough to generate the required flowrates, hence more intrusive forms of artificial lift are installed such as ESPs, positive cavity pumps (PCP) and beam pumps (BP). Pump bypass systems have been developed for these wells to regain production-logging access, however these were not designed for low rate wells.
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)