Phummanee, Sutthipat (PTT Exploration and Production Public Company Limited) | Rittirong, Ake (PTT Exploration and Production Public Company Limited) | Pongsripian, Winit (PTT Exploration and Production Public Company Limited) | Phongchawalit, Natthaphat (PTT Exploration and Production Public Company Limited)
The objective of this paper is to demonstrate the implementation of downhole water drain (DHWD) technique to improve gas recovery factor for bottom-water-drive gas reservoir in the multi-thin reservoirs system in Arthit field. This technique was selected as an alternative method to defer water loading in the wellbore by preventing early water breakthrough meanwhile enhancing gas expansion. Project planning, operation, and performance evaluation are the gist of the discussion here.
Candidate selection was the critical first step to the success of DHWD technique. The suitable wells require a gas-water contact reservoir at the upper part of the well and totally depleted reservoirs below it. After identifying candidates, bottomhole pressure survey was performed to investigate the reservoir condition for reservoir simulation. Both gas and water layers above and below the gas-water contact were perforated as designed. A plug was set between the perforated gas and water layers to isolate the flow. This allows gas to be produced to surface while water flows downwards to the depleted reservoirs.
The key parameters used in evaluating the effectiveness of DHWD technique are incremental gas recovery and water breakthrough time. According to the production history of existing gas-water contact reservoirs in Arthit field, massive water production generally starts to intrude after 1.35 months of production at which water-gas ratio increases above 50 STB/MMscf. As a consequence, the gas production sharply declines and eventually ceases to flow. The water breakthrough time of the two trial wells in which DHWD technique was applied is significantly slower than the field average. One was observed water breakthrough after 2.05 months and the other was after 5.40 months of the production. Gas EUR gain is the difference between the EUR when applying DHWD technique by declined curve analysis and the expected EUR of conventional production by statistical method. The results from the two trial wells indicate that DHWD technique can significantly improve the EUR by 110% and 871%.
Downhole water drain is a groundbreaking technique that can be practically implemented to enhance gas recovery of bottom-water-drive gas reservoirs. This technique is recommended for gas field as an alternative strategy since it yields substantial additional reserves gain while required only a small additional cost from the additional perforation of water sand and permanent bridge plug.
Multiphase pumping technology is continuously emerging in the oil industry as solution for oil and gas field production where limitations with conventional pumping systems occur. This paper presents the recent research on the application of a new multiphase down-hole twin-screw pump on the base of reservoir and production simulations of an offshore oilfield.
Many seismic attributes today reveal fault and fracture patterns. However, these fault attributes often suffer from noise or artifacts in the input data, resulting in data that is not high-enough a quality for automatic fault pickers to use directly without a post-attribute enhancement. In this paper, we introduce a new method to enhance the fault patterns in a 3D seismic volume using an array of 3D log-Gabor filters, which optimize fault planes by identifying isolated sections as a coherent fault or fracture while suppressing footprints, noise, and other artifacts. The resulting fault energy volume, which represents the enhanced faults, assists with fault interpretation. Unlike conventional fault enhancement, our method is inspired by the neuronal mechanism of orientation perception in the brain, and does not require fault orientations as input for filtering. Instead, fault dip and azimuth are two additional output attributes which are estimated during the filtering process, and are used for further orientation analysis or volumetric fault visualization. The proposed method is applied to real-world 3D seismic data located at
Presentation Date: Monday, October 17, 2016
Start Time: 3:45:00 PM
Presentation Type: ORAL
Pennsylvania has a 150-year history of oil and gas production-the longest of any state- and this enduring activity has resulted in the drilling of more than 330,000 known wells. However, unknown wells may exist because innumerable wells were drilled during Pennsylvania's early years of intense oil and gas development when incomplete records were kept of well locations. The concern is that early wells are likely to be unsealed because there were no laws that required effective plugging when the wells were abandoned. Now, many unrecorded wells are thought to be in areas of emerging shale gas and shale oil development where open wellbores might provide a pathway for undesired upward migration of fluids and gas from hydraulically fractured reservoirs. Because of this concern, Pennsylvania regulators have asked operators to locate orphaned and abandoned wells within a 1000-ft- buffer of new wells before hydraulic fracturing.
The National Energy Technology Laboratory conducted high-resolution, helicopter magnetic surveys over four large land tracts in western and north-central Pennsylvania where historic oil and gas production has taken place and where unconventional oil and gas resource development is occurring or expected. The project's objective was to evaluate the ability of helicopter magnetic surveys to locate existing wells in heavily vegetated areas of varying terrain. Magnetic surveys locate wells by detecting the unique magnetic signature of vertical, steel well casing, which is depicted on magnetic maps as a "bull's eye" type anomaly centered directly over the well. To mitigate for the likelihood that wellbores exist where most or all casing has been removed, this study augmented helicopter magnetic data with supplemental information from farmline maps, state well databases, historic air photos, and digital terrain models generated from LiDAR datasets- all information that is publically available for areas within Pennsylvania.
The four surveyed areas include: 1) a 7 km2 (2.7 square mile) tract of privately owned land in Washington County with historic oil and gas production and where gas is now being produced from five, horizontal Marcellus Shale wells; 2) a 17.7 km2 (6.8 square mile) area of state owned land (Hillman State Park) in Washington County with historic oil and gas production and where the uppermost well casings were often cut off or buried by 1950's era surface coal mining; 3) a 28 km2 (10.8 square mile) block of state-owned land in the Susquehannock State Forest of Potter County where gas was once produced from the Oriskany Sandstone, but it is now a gas storage field; and 4) a 37.7 km2 (14.6 square mile) area of state owned land (Oil Creek State Park) in Venango County, which contains more than 900 known wells, including some of the oldest oil wells in the United States. Ground surveys to confirm well targets from the helicopter magnetic surveys have been completed for two of the four areas flown including: 1) the private land tract in Washington County, PA with Marcellus Shale development and 2) the area in Susquehannock State Forest that is now a gas storage field.
At the private land tract in Washington County, the helicopter magnetic survey identified 13 well-type magnetic anomalies within 1000 ft of the five horizontal Marcellus wells located there. The ground investigation confirmed that nine well-type magnetic anomalies were wells while four magnetic anomalies were found to arise from non well sources. One additional well with a weak (initially overlooked) magnetic anomaly was found using historical air photos. Of nine confirmed wells, six wells had recorded locations in Pennsylvania's statewide oil and gas wells database (PA*IRIS/WIS). However, the PA*IRIS/WIS locations were sometimes too inaccurate for the wells to be located in the dense underbrush.
At the gas storage field in Susquehannock State Forest, the helicopter magnetic survey identified 81 magnetic anomalies, including 55 well-type magnetic anomalies. A subsequent ground investigation confirmed that 30 of the 55 well-type magnetic anomalies were well locations. All confirmed wells except one were listed in the PA*IRIS/WIS state oil and gas well database and the locations provided were sufficiently accurate to locate the well in the field. The helicopter magnetic survey also identified two gas transmission pipelines with pulsed cathodic protection and multiple short pipeline segments without cathodic protection.
Helicopter magnetic surveys identified 192 well-type magnetic anomalies within Hillman State Park and 742 well- type magnetic anomalies within Oil Creek State Park. The ground investigation to confirm well locations in the two state parks had not commenced at the time of this report.
Preliminary observations from this study are: the PA*IRIS/WIS well database is incomplete for wells drilled between 1890 and 1920, the era of early well drilling at the Washington County Marcellus Area. Only six of nine confirmed wells were listed in this database. the PA*IRIS/WIS well database contained 29 of 30 wells found by the helicopter magnetic survey at the gas storage field in Susquehannock State Forest. Wells in this area were drilled post-1950 to produce from and store natural gas in the Oriskany Sandstone. This area contains active gas storage wells and plugged and abandoned gas wells. high resolution magnetic surveys acquired from low-flying aircraft provide accurate locations for wells with steel casing. However, wells with no steel casing exhibit weak or no magnetic anomaly. the inspection of publically available historic air photos or LiDAR imagery for well signatures can sometimes augment helicopter magnetic surveys by identifying well locations where the steel casing was recovered for reuse or salvage. complete casing strings are not needed for detection by helicopter magnetic survey although the minimum casing requirement for detection is not known.
the PA*IRIS/WIS well database is incomplete for wells drilled between 1890 and 1920, the era of early well drilling at the Washington County Marcellus Area. Only six of nine confirmed wells were listed in this database.
the PA*IRIS/WIS well database contained 29 of 30 wells found by the helicopter magnetic survey at the gas storage field in Susquehannock State Forest. Wells in this area were drilled post-1950 to produce from and store natural gas in the Oriskany Sandstone. This area contains active gas storage wells and plugged and abandoned gas wells.
high resolution magnetic surveys acquired from low-flying aircraft provide accurate locations for wells with steel casing. However, wells with no steel casing exhibit weak or no magnetic anomaly.
the inspection of publically available historic air photos or LiDAR imagery for well signatures can sometimes augment helicopter magnetic surveys by identifying well locations where the steel casing was recovered for reuse or salvage.
complete casing strings are not needed for detection by helicopter magnetic survey although the minimum casing requirement for detection is not known.
Until the offshore industry stepped off the continental shelf, the main marine geohazard risk addressed from geophysical data was the presence of shallow gas. Presence had been described using a number of nonstandard approaches for its potential presence - distinct from the actual risk it presented to operations. In the 1990 "UKOOA Guidelines for the Conduct of Marine Rig Site Surveys," a standardised nomenclature was suggested that was largely taken up as a standard by the industry. At around this point in time, the industry had begun a move off the shelf and into deep water and, with this, a number of new geohazard issues started to present themselves (e.g.
Algebraic multigrid (AMG) represents a class of efficient preconditioners for large and sparse linear systems arising in particular from discretized elliptic partial differential equations. In the context of reservoir simulation, a standard preconditioner for the linear solver is the so-called CPR-AMG in which AMG is applied to an approximated pressure subsystem. In this method, AMG is the bottleneck for scalability because it involves a lot of communications across processors in particular for the setup phase, which constructs the coarse levels according to the coefficients of the Jacobian matrix. The goal of this work is to decrease the overall cost of the CPR-AMG in parallel by combining two different coarsening strategies: the first levels are computed using an aggregation scheme whereas the coarsest levels are treated using a classical point-wise Ruge-Stüben (RS) scheme. AMG preconditioners constructed using classical coarsening schemes are able to achieve good convergence rates of the preconditioned iterative method. The complexities of the multigrid hierarchies can be quite high and thus the classical AMG may be expensive in terms of memory requirements and computational times. Aggregation AMG methods, on the other hand, provide better means of complexity control and consequently the setup time required to construct the preconditioner can be considerably lower. The efficiency of the aggregation AMG methods, however, deteriorates with the increasing problem size although the two-level convergence rates can be very good. To take advantage of both the aggregation and classical AMG, we consider combining both approaches within one hierarchy in order to decrease the setup time of the AMG preconditioner while retaining the convergence properties of the two-level aggregation method.
Gas recovery factor from water drive gas reservoirs is very low compared to recovery made from depletion drive gas reservoirs. Other problems associated with gas recovery from water drive mechanism include high residual gas saturation in the water invaded zone of the reservoir, high volume of produced water, abandonment at high reservoir pressures and high possibility of hydrate formation in pipe lines. The use of carbon dioxide (CO2) in displacing natural gas from volumetric gas reservoirs has been studied, practised and is successful. In this paper, it is proposed that extending this practice to gas reservoirs under strong water drive mechanism can improve recovery and control water influx.
CO2 is denser than natural gas and water is denser than CO2. The different densities of these fluids can be taken advantage of to boost natural gas recovery from water drive gas reservoirs. The continuous CO2 injection process at the gas water (g/w) contact can partially prevent water encroachment into the system. The technique can change the water drive mechanism to full or partial depletion drive where CO2 will separate the natural gas zone from direct contact with the water zone. Any eventual water invasion into the reservoir affects the CO2 zone, not the upward moving natural gas zone.
This technique was studied by simulation using data from a lean gas reservoir under strong water drive. Two cases were considered. In the first case, which is the reference case, gas production under water drive was allowed for 30years. In the second case, CO2 was injected at the initial gas water contact for the same number of years. Simulation results showed that water production from the reservoir was drastically reduced to about 60% in the second case because the rate of water influx into the reservoir was controlled. Gas recovery from two producer wells out of three that were considered improved above 10% and gas condensate recovery was improved to about 4% over the period of production that CO2 was injected.
1. Description of the Material. While the CO2-enhanced oil recovery process has been successfully applied in onshore oil reservoirs, no commercial CO2-EOR is yet underway in the offshore of the Gulf of Mexico (GOM). However, several offshore CO2-EOR projects are being implemented overseas, including an early application of CO2-enhanced oil recovery in the giant Lula oil field offshore Brazil. These experiences provide confidence that, where the reservoir conditions for EOR implementation are favorable, the CO2-EOR process can be extended to the offshore Gulf of Mexico, providing increased domestic oil production and secure settings for storing CO2.
2. Application/Development. The paper examines a large set of over 500 shallow and deep water offshore fields to identify 140 oil fields (containing 696 oil reservoirs) screened as prospective for CO2-EOR. It then uses “streamline” reservoir simulation and an offshore CO2-EOR cost model to: (1) assess the economic feasibility of applying CO2-EOR in these oil fields/reservoirs; (2) project the volumes of additional oil recovery that would result from application of current as well as advanced offshore CO2-EOR technologies; and (3) estimate the volume of CO2 that could be stored with CO2-EOR in GOM’s oil fields.
3. Results, Observations, and Conclusions. The paper identifies the urgent need to initiate CO2-EOR in maturing shallow water oil fields of the GOM, before the platforms are removed and these oil fields are abandoned. The paper also identifies opportunities for undertaking early application of CO2-EOR in newly discovered deep water oil fields, helping improve overall economic viability. Finally, the paper examines the potential of applying CO2-EOR to the large undiscovered oil resource potential remaining in the deep waters of the GOM OCS. The paper examines the potential sources of CO2 in the Gulf Coast area that could provide CO2 supplies for offshore oil fields, including existing natural sources, the industrial facilities planning, CO2 capture, and the large fleet of coal- and natural gas-fired power plants in the area.
4. Significance of Subject Matter. The information in this paper provides a fresh perspective on the challenges and opportunities of pursuing CO2-EOR in the offshore oil reservoirs of the GOM.
Detection and interpretation of fault systems are crucial to seismic interpretation and reservoir characterization. We introduce a new attribute that aims at detecting faults while preserving fault information and handling its local variations. First we use predictive painting to form a structural prediction of seismic events from neighboring traces. Then we compute prediction residuals and find the smallest prediction-error interval at each point that is the best representative of fault information at that point. In comparison with other fault attributes, such as classic coherency or similarity, predictive coherency allows for a balance between highlighting of faults and protection of fault information and its local variations. To asses performance of the proposed attribute in highlighting faults, we compared results from our attribute with analogous attributes over the same dataset. The comparison demonstrates the effectiveness of fault detection using predictive coherency.