The ever increasing operator demands and objectives to mill fast and efficient windows has led to the development of innovative milling technology. New lead mill profiles and cutting structures have replaced old crushed carbide technology.The new design utilizes inserts brazed into pockets machined in the mill head. Mills dressed with the new cutting structure are able to effectively mill a casing window and drill formation rat hole in less time than it took with the welded-on crushed carbide technology.
With this new design, operators are now afforded an option. In medium to hard formations, the new cutting structure can be used to mill the window and drill rat hole in one trip. While sidetracking in formations with high compressive strengths, Polycrystalline Diamond Compact (PDC) inserts can be utilized. The use of the new cutting structure in a one trip sidetrack system can result in substantial cost savings, improved milling reliability and a higher quality window.
The combination of new cutting elements and mill profile has proved to be economically sound allowing for consistency of product manufacturing and has eliminated the potential variances inherent in the welding processes. The system design and cutting structure reduces torsional resistance providing for smoother in-gauged milled windows in one trip.
This paper updates an earlier paper with the concepts of using the new cutting structure and presents the new technology and recent case histories of four sidetrack operations.
In order to supply operator demands for milling windows faster and more efficient, a commitment was made by an oil service company to develop new technology and sharing this new technology within the corporate business units. The sharing of technology has led to innovative drilling technology to be used in milling full-size casing windows at a lower cost. The working together of the diamond manufacture business unit, the PDC bit business unit, and the remedial services business unit has proven to be very advantageous in the advancement of diamond technology and mill head design.
The use of multiple axis milling machines has led to precise and consistent manufacture of the Lead Mill profile and cutting structure.The mill profile and cutting structure are responsible for cutting the window in casing and for drilling formation. The cylindrically shaped inserts are brazed into pockets milled into the mill cutting structure.The technique used to braze the inserts into the pockets has proved to be reliable and has greatly reduced the damaging effects caused from excessive heat from the welder's torch.
Changing the Lead Mill cutting structure from the crushed tungsten carbide and/or pre-formed tungsten carbide to the cylindrically shaped insert cutting structure has had a profound impact in the Lead Mill performance and reliability.
Advancements in Lead Mill profile design, diamond technology, and cutting structure density has led to the development of the Hard Formation Mill. As more sidetracks were performed in formations with compressive strengths of greater then 20,000 psi, the need for a sidetrack mill that can cut a window in casing and drill formation in one trip was apparent.
Most well controllers require a pumping unit installation and difficult data analysis to determine and regulate for optimum well productivity.Wells with ESP's, PCP's or no pump (such as flowing wells, gas wells, etc.) require complicated and expensive equipment to accomplish the same goal.However, a wellhead-mounted, remote-operated, high-sensitivity acoustic fluid level "gun" has been developed which propels a "pressure wave" into the casing up to 100 times per day and sends the information (including casing pressure and other essential data) to any location (if desired).
Based on the information gathered (and automatically or manually analyzed), the units can be set to: regulate pumping speed; shut a well on and off ("time-clock" a well); trigger pump-off or other alarms; shut in safety valves; regulate chokes.In addition, the instrument's advanced "wave form" generation combined with an ultra-sensitive microphone can accurately detect the fluid level,perforations, holes in casing and tubing, paraffin/scale buildup, as well as down-hole equipment location within 5-10 feet in wells up to 20,000 feet depth.
Unlike most fluid level data, the information can be presented digitally on any computer, and adjusted to any sensitivity to maximize the accuracy of as well as the amount of data that can be gathered and utilized.Third-party analysis and monitoring can be arranged for companies that have minimal or no technical support.Important to note is that this technology is available for approximately the same cost as the well controllers offered by the industry today.Now one truly CAN "stick your head down there" and see just what's going on, as often as desired.
The advantages are obvious:minimize expensive electrical use; maximize life of well equipment; produce everything that enters the well; true determination of well productivity; prevent or quickly identify downhole problems; control wells safely onshore and offshore; identify gas well loading; minimize labor costs and human error.
Ilseng, Jeffery Ron (Dan A. Hughes Co.) | Hoskins, Lee (Dan A. Hughes Co.) | Matthews, Hugh Lee (H. Lee Matthews Consulting) | Fuller, George Allen (Halliburton Energy Services Group) | Pronger, David Neil (Halliburton Energy Services Group) | Ravi, Krishna (Halliburton Energy Services Group)
Development of marginal fields offers unique challenges during drilling, completion, stimulation, and production. The underlying objective should be to maximize the value of the field over its productive lifetime. Every phase of the well construction needs to be fully evaluated for subsequent impact on the safety and economics of producing oil and gas from the field. Log evaluation of formation type, thickness, and characteristics may determine the final completion plan, although lack of natural barriers from close water contact may be of major concern when a large stimulation program is required. Specialized low-density cementing systems may be necessary for maintaining satisfactory equivalent circulating density (ECD) for coverage across weak formations. These low-density systems can be prepared either by an engineered foaming operation or by the use of specialized additives blended with cement to lower the density, but production quality properties should be maintained. Consideration should also be given to the final cement sheath properties, which can provide isolation for the "life of well" following cyclic pressure loading from stimulation, testing, and flowing phases.
This paper addresses the advantages and disadvantages of the historical approach to constructing and producing horizontals. Completion processes and procedures with emphasis on cementation designs and best practices for horizontal casing are presented with major focus on resulting production rates. These case histories will cover both cemented and uncemented producing wells. Also included will be new methods for predicting cement failure modes as a result of cyclic pressure loading from stimulation jobs. Recent design procedures and ensuing effect for maximum value of the producing asset for life of the field will be compared with historical procedures.
Occasionally during a pre-frac injection test the observed friction pressures are much higher than expected.These tests have frequently led to significant delays and expense in tight gas wells re-perforating the interval to be fractured in order to remove this ‘excess near-wellbore friction' pressure.This paper presents a method to identify and mitigate the effects of two-phase flow during an injection test.Examples are presented which encountered very high apparent near-wellbore friction pressures that were actually due to two-phase flow.Subsequent testing with 100% liquid injection revealed normal near-wellbore friction pressures.A technique of repeating the test after a variable shut-in time has routinely served to eliminate the need for a costly and time-consuming re-perforating job.
Today's oilfield is data-rich-but suffers due to a lack of end-user access and analysis of the available information. Important wellhead data that historically has been gathered through daily wellsite visits by operating personnel often goes unobserved because of manpower restraints. Therefore, recognition of operating problems based on such visits or on diagnostic analysis of the available data can be delayed or even lost to the operating company.
The flow of a gas in to a wellbore in a production well can result in the evaporative cleanup of water blocks. This occurs primarily due to the expansion of gas resulting in additional water being evaporated in the near wellbore region. This study presents for the first time, equations and a model to calculate the rate at which the water block is removed in both fractured and unfractured gas wells.
It is shown that the removal of water by the expanding gas leaves behind a saturation profile that is qualitatively different for low and high permeability rocks. As a consequence the increase in gas relative permeability or the well productivity with time can vary substantially depending on the rock permeability and the well drawdown. The model allows us to compute the impact of evaporative cleaning on well productivity.
It is seen that high permeability rocks clean up significantly faster. It is also observed that unfractured wells may require a very long time to cleanup. Large pressure drawdowns as well as the use of more volatile fluids such as alcohols result in significantly faster cleanup. A distinctive feature of the study is that the model equations are formulated and solved completely without the assumption of skin factors for the damage zone. Thus the prediction of cleanup rates can be made more accurately.
While each engineering discipline may have a piece of the puzzle to find the best solution for achieving optimized production rates and economics, we can only hope to achieve the best results if we use a total system (reservoir to sales point) approach. Relatively simple to use software tools are available to help and can be easily applied, especially on gas wells. However, effective use of these tools will require the engineering disciplines to break down silos, possibly compromise on using their "favorite" tools and work together. Examples and case histories on gas wells are shown to demonstrate how each discipline looks at solving problems and how better solutions are found using an integrated production model (IPM).
The objective of this paper is to review the current methods of determining how the effects of wellbore hydraulics are incorporated into the evaluation of the productivity of a horizontal well.Wellbore hydraulics includes the effects of friction, acceleration, gravity, and fluid influx.Knowledge of the pressure distribution within the horizontal wellbore is important to more accurately determine the performance of the horizontal well and aides in the design of the well profile, completion, and stimulation.
Jha, Madan K. (Schlumberger) | Tran, Thanh B. (JO - ChevronTexaco/KOC) | Hagtvedt, B. (JO - ChevronTexaco/KOC) | Al-Haimer, Mohammad (JO - ChevronTexaco/KOC) | Al-Harbi, Musaad S. (JO - ChevronTexaco/KOC)
The South Umm Gudair (SUG) oil field located in the Neutral zone between Kuwait and Saudi Arabia has produced since 1968 from an active water drive carbonate reservoir of Lower Cretaceous age.The lower zones are homogenous intervals of higher permeability which appear to be sufficiently swept by natural water drive over a period of time. The upper zones of the reservoir are more heterogeneous and have lower permeability in the range of 50-150 millidarcies.These upper zones are relatively thin and are bound by tighter intervals that act as effective barriers to the natural water drive system. Due to the presence of barriers and low permeability intervals, these zones have been poorly swept resulting in significant volumes of by-passed oil remaining in these parts of the reservoir.
The new approach of exploiting these reserves bydrilling and completing 4 horizontal and 2 horizontal side track (HST) wells targeting the lower permeability portions of the reservoir in the SUG field since January 2004; have yielded considerable success in extracting significant incremental oil production with the added benefit of very low water cut.This success has led to field development plan to recover un-swept oil reserves from these low permeability zones.This paper summarizes the various aspects of field development plan taking into consideration geology, reservoir data and production data while highlighting the successes of the new horizontal and HST wells in the low permeability reservoir portions of the SUG field.
The SUG field was discovered in 1966, and put on production in 1968. The primary recovery mechanism is a combination of edge and bottom water drive aquifers. The field has been developed initially by vertical wells targeting all productive zones; which have been perforated and produced commingled. The SUG field today produces approximately 70,000 Barrel of Oil Per Day (BOPD) and 80,000 Barrel of Water Per Day (BWPD) from 64 active oil wells, out of which 23 are horizontal and HST wells.All wells are produced by artificial lift using Electrical Submersible Pump (ESP).Location and structure maps of the field are shown in Fig.1 and Fig.2.
The Ratawi Oolite carbonate reservoir is an anticlinal structural trap.The Early Cretaceous reservoir section was subjected to folding during the Late Cretaceous and Tertiary times associated with compressional events.The dominant carbonate lithologies consist of pelloidal/skeletal grainstones with lesser amounts of packstones, wackestones and minor mudstones.The Ratawi Oolite section at SUG is considered to have been deposited on a very broad, shallow, carbonate platform.Deposition occurred in inner ramp tidal flat, lagoon, and higher energy ramp crest environments.
Deeper water more micritic lithologies, associated with flooding events at the base of these depositional cycles, form important reservoir barriers across large portion of the field.Low energy, tight, shallow shelf mudstone and wackestones of Upper Ratawi Oolite formation overlie the porous reservoir section.
The upper and the lower part of the reservoir are fairly different with respect to formation characteristics. The lower zones (M4 to M12) are relatively homogeneous with permeabilities ranging from 300 to 400 millidarcies. The upper zones (M1 to M3b) of the reservoir are more heterogeneous andhave lower permeabilities ranging from 50-150 millidarcies (called Low Permeability Reservoir).These intervals have a fining upward lithologic signature, as evidenced from the open hole logs of the wells.The reservoir layers are illustrated in the cross-section shown in Fig. 3.
The Effect of gas-water content phase behavior on mature methane rich gas wells has been investigated and found to be extremely detrimental. The wells performance becomes stressed and ultimate operating reserves will deviate negatively to previously established developed reserves due to fluid loading. The fluid loading phenomenon is usually associated with a gas production rate falling below the minimum mist flow rate required for the existing wells, producing tubular geometry. This analysis presents a method to reverse the ill effects of down hole phase behavior and suggest an alternate lift option. The advantage of this method is that it normally requires little or no down hole reconfiguration, and successful application would be superior to current artificial fluid lift operations. The resultant would translate to restoration or original developed reserves and quite possibly enhance production rate.
It is only recently within the oil and gas industry history, that the concept of stripper gas well production has been recognized and addressed. The enhancement and retention of natural gas production has largely been secondary or non-existent compared to the new technologies directed toward the development of advanced oil recovery techniques. However, the future of natural gas has rocketed to the forefront of valued energy commodities. This is a result of its continued and prolific trend increase in demand. Natural gas has become the environmentally preferred fuel to meet future domestic power requirements. The efficient production and protection of established reserves has become of paramount value and importance in the light of national energy security and economic interests. Industry and attendant governmental agencies are now working in concert to address this issue and have successfully supported new and improved lifting technology.
A detrimental phenomenon exists within dry methane rich gas areas. That is, those natural gas reservoirs that might be described as low water saturation and devoid of any free water, or liquid hydrocarbon production throughout their early life. Mature production, invariably, commences to show signs of fluid loading. Hence, an operator will make attempts to counteract this performance by some mechanical adjustments. Pumping units, plunger lifts, downsized tubular, down-hole separators and soap sticks, are some of the common response strategies. All may off temporary, but not necessarily sustained relief. The operator's ultimate inability to cope with this phenomenon, however, usually results in the premature abandonment of the individual well and loss of developed gas reserves.