The Gas-Liquid Cylindrical Cyclone (GLCC) has repeatedly proven itself in laboratory and field tests, as well as in actual field applications, as a viable alternative to the conventional gravity-based gas/liquid separator. Large conventional gravity-based vessels have been relied upon since the inception of the petroleum industry to separate oilfield production of oil, water, sand, and gas. However, economic and operational pressures continue to force the petroleum industry to seek smaller, less expensive and more appropriate separation alternatives in the form of compact separators, especially for offshore and subsea applications. As compared to the vessel-type separators, a compact separator such as the GLCC is a simple, low-cost, low-weight separator that requires little maintenance and is easy to install and operate. Furthermore, the capabilities to accurately predict various performance characteristics, e.g., liquid carry-over and gas carry-under, of the GLCC have far surpassed those capabilities for conventional vessel type separators. The scope of this paper is to present the state-of-the-art of the GLCC technology for variety of applications in the oil and gas industry.
At present, over 1,000 GLCCs have been installed in fields around the world. Details of typical field applications are presented and discussed in this paper. In addition, data from field type facilities, namely, Texaco's Humble flow loop and Colorado Engineering Experiment Station Inc. (CEESI) are presented. These data illustrate GLCC performance at high pressures (up to 1,000 psi) with a variety of hydrocarbon fluids. The results presented include, gas carry-under (GCU), liquid carry-over (LCO) and GLCC control data. Additional field testing of the first integrated GLCC compact separation system carried out in Daqing oil field experiment station are also presented.
The technology for state-of-the-art GLCC field applications and some laboratory and field testing results presented in this study, will help petroleum engineers to better understand, design and deploy GLCC technology in their field operations.
Since the early 1990's the industry has shown keen interest in the development and application of the Gas-Liquid Cylindrical Cyclone (GLCC©) due to its significant advantages over conventional gravity based vessel separators. These include simplicity in construction, compactness, low weight, and low capital and operational costs. Compact cyclonic separators have been used in primary separation, well test metering systems, control of gas-liquid ratio for multiphase meters, pumps and de-sanders, gas scrubbing for flare gas, and external pre-separation upstream of existing conventional separators. Currently, the GLCC is being considered for a variety of subsea applications, and will soon be installed as part of a subsea multiphase pumping system.
The pioneering studies on the GLCC were conducted by Chevron (Liu & Kouba, 1994 and Kouba et al. , 1995) for the development of the multiphase metering loop incorporating the Net Oil Computer©, as shown schematically in Fig. 1. The GLCC technology has been rapidly developed and disseminated by industrial cooperation, namely, through the Tulsa University Separation Technology Projects (TUSTP) industry/university research consortium.
Schechter, D.S. (Texas A & M University) | Putra, E. (Texas A & M University) | Baker, R.O. (Epic Consulting Services Ltd.) | Knight, W.H. (Pioneer Natural Resources USA Inc.) | McDonald, W.P. (Pioneer Natural Resources USA Inc.) | Leonard, P. (Pioneer Natural Resources USA Inc.) | Rounding, C. (Pioneer Natural Resources USA Inc.)
This paper addresses the field activities to develop a 15 well, 60-acre CO2 pilot in the Spraberry Trend Area in west Texas. Spraberry reservoirs originally contained 10 Bbbls OOIP of which less than 10% has been recovered. Waterflooding has been documented as a poor recovery technique. We demonstrate that an unexpected response to water injection may alter conventional wisdom. We also describe a unique characterization of the natural fracture system with step-rate injection testing, buildup and multi-well interference testing, and tracer surveys.
The Spraberry Trend Area in west Texas was discovered in 1949 and continues to produce 60 Mbopd from more than 7,500 wells from an eight county area encompassing over 2,500 square miles. Spraberry reservoirs originally contained some 10 Bbbls OOIP of which less than 10% has been recovered.
The Spraberry Trend Area has proven to be elusive to engineers since discovery. Half a century later, the reservoir has maintained the status of one of the more complicated naturally fractured reservoirs to understand or forecast. There are three sets of highly permeable fractures distributed among the two pay intervals in the Upper Spraberry, the 1U and 5U sand (there is the lower Spraberry that is not discussed here). The fractures are stress-sensitive and the fracturing pressure of shales zones are very near fracturing pressure for Spraberry oil sands. Oil recovery is dominated by the imbibition mechanism, however Spraberry sands are weakly water-wet and the matrix permeability is very low. Waterflooding has not been widely applied in the Spraberry Trend Area. In the past, water injection wells were aligned parallel to the major NE-SW fracture trend and perpendicular to a line of production wells (line-drive). Line-drive pattern configuration in anisotropic reservoirs is commonplace as is shown in Fig. 1. However, aligning injectors along the same fracture trend with producers was viewed as unwise since the fractures would rapidly conduct injected water to the production well.
The general idea was to build interference between injectors along the fracture trend and force injected fluid to a line of producing wells, also aligned along the primary fracture trend. We believe this de facto approach to water injection in Spraberry has been the primary reason this tremendous resource is so underutilized. The fractures are highly anisotropic1, and the matrix permeability is very low2,3 thus requiring high rate fluid injection to force fluids to a line of production wells. The injection rate required to achieve this communication probably creates hydraulic fractures with variable orientation. The small difference in stress anisotropy between adjacent sand and shale layers (as measured in a mini-frac test) and the unquestionable stress sensitivity of the fracture system may result in preferential channeling in non-pay resulting in poor sweep efficiency.
The tremendous size of the reservoir, large number of active and plugged wells, lack of historical production/injection data, and fluid migration across lease boundaries have hampered assessment of water injection over the years. This has resulted in a lack of confidence in the application of water injection in Spraberry reservoirs.
In this paper, we will review the five most documented water injection tests in order to reach stage of development practices that could eventually unlock the key to successful water injection. We will review the results of water injection in the current CO2 pilot area in order to use this information for development of widespread waterflooding throughout the Spraberry Trend Area. The documented waterflood projects in Spraberry are listed below:
Atlantic Richfield Pilot (1952)
Humble Pilot (1955)
Albright, James N. (Los Alamos National Laboratory) | Woo, Daniel M. (Mark Products) | Fairbanks, Thomas D. (Nambe Geophysical, Inc.) | Thomson, James C. (Lithos, Inc.) | Howlett, Don (Texaco E&P, Inc.) | Barge, David (Texaco E&P, Inc.)
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This article is a synopsis of paper SPE 37619, "Reciprocating Cement Slurries After Placement by Applying Pressure Pulses in the Annulus," by J.P. Haberman, SPE, Texaco, and S.L. Wolhart, SPE, Gas Research Inst., originally presented at the 1997 SPE/IADC Drilling Conference held in Amsterdam, 4-6 March.
Multiphase fluid handling technology has been applied worldwide in its commercial version since 1984, specializing in pumping medium and light crude oil and its associated gas. This technology was applied to Venezuela's heavy/extra-heavy crude oils in 1995 in a field evaluation in Corpoven's Arecuna Field, Hamaca Area in the Orinoco Belt. This was done by installing a multiphase pump with a capacity of 53.5 MSTBD equivalent (5.5 MSTBD of liquid and 48 MSTBD equivalent of gas), an intake pressure of 30 psi, and a maximum discharge pressure of 700 psi (a pressure differential of 670 psi). This equipment was designed to handle the production associated with eight wells, located 5.28 miles from the nearest crude oil separation and treatment facilities.
After 3260 hours of continuous operation, the results obtained from the evaluation of the two-screw multiphase pump show normal behavior, handling a flow of 52 MSTBD equivalent (11 MSTBD of liquid and 41 MSTBD equivalent of gas), an intake pressure of 20 psi, and a discharge pressure of 300 psi (a pressure differential of 280 psi). The average power consumption was 400 kw/hr. Results empowered Corpoven to include multiphase technology as a component of its existing new developments. Multiphase pump low pressure intakes have resulted in lower pressures at well heads (from 140 psi to an average of 80 psi), allowing a 12.5% production increase, equivalent to 220 STBD.
The purpose of this paper is to reveal the results obtained from a field evaluation of a multiphase pump application in Venezuelan heavy/extra-heavy crude oil production areas. Additionally, this paper includes an economic analysis of multiphase versus conventional gathering facilities and operating recommendations based on a commercial pilot test.
Corpoven's heavy/extra-heavy crude oil production has traditionally been handled and transported through a flow station-production station arrangement, where produced fluids are collected, separated, measured, and subsequently treated and transported to different destinations (compressor plants for gas and tank farms for crude oil). This conventional scheme has worked efficiently when the processes are continuously optimized, however, the costs of installations and major equipment have increased considerably, in addition to the operational inconveniences represented by the presence of crude oil storage sites scattered around the producing areas. In order to take advantage of new technologies that add value to processes of gathering, handling and transportation of produced fluids to the production stations, and reduced investment and operating costs, beginning in 1995 Corpoven has began to apply multiphase pumping technology on heavy/extra-heavy crude oil production in the Arecuna field within the Orinoco Belt.
Schechter, David S. (New Mexico Petroleum Recovery Research Center) | McDonald, Paul (Parker and Parsley Petroleum USA, Inc.) | Sheffield, Tom (Parker and Parsley Petroleum USA, Inc.) | Baker, Richard (Epic Consulting Services, Ltd.)
The Spraberry Trend Area in West Texas encompasses a productive area greater than 2,500 mi2. Spraberry was once deemed, "The largest uneconomic field in the world." The marginal economics and low recoveries of producing in Spraberry are well documented and have effectively prevented comprehensive reservoir characterization yet the Spraberry Trend Area continues to produce nearly 60 Mbopd from more than 7,500 wells and has produced 700 MMbbls during the life of the reservoir. Many wells have been abandoned due to low productivity and many more face the same fate unless new technology becomes available which will improve recovery over the current low value. Spraberry Trend Area reservoirs originally contained some 10 Bbbls OOIP of which less than 10% has been recovered. Obviously, the oil remaining in place represents a tremendous EOR target.
Many of the large Spraberry Units which were once operated by major oil companies have been acquired by independent oil companies. Development of these units has resulted in extensive in-fill drilling from 1991 through 1995. The consolidation of large tracts of unitized Spraberry production under one operator combined with a plentiful, local and relatively inexpensive supply of CO2 has raised some interesting questions. This paper addresses the necessary background and future plans for a proposed CO2 pilot in the Upper Spraberry.
The work in this paper also demonstrates the value of consolidating old data from several operators aud integrating with more recent data as a necessary step towards comprehensive fracture characterization, a precursor for developing all possible process options before vast numbers of Spraberry wells are plugged and abandoned.
CO2 injection in Spraberry has never been attempted. The reasons are clear. Naturally occurring fractures have been known to dominate both initial production and subsequent waterflood performance throughout the Spraberry Trend. The implicit expectation of excessive channeling prevented operators from considering gas injection.
However, the following factors led to implementation of a CO2 pilot in the Spraberry Trend:
1. The success of a CO2 pilot in the naturally fractured Midale reservoir as reported by Beliveau et. al.
2. Recent studies performed which indicate gas injection may be a viable process for low permeability fractured reservoirs.
3. The operator of the pilot has a considerable unitized acreage exposure in the Spraberry Trend making the reward/risk much greater than several companies operating individual units.
4. An abundant supply of CO2 in West Texas in very close proximity to the heart of the Spraberry Trend.
5. The willingness of the DOE to cost share the venture in order to avoid permanently losing a large national resource.
From experience in Midale and initial work performed on this project, it is clear that understanding the fracture system in the pilot area is key to the success of the pilot. Interpolation of the results to the whole of the Trend is key for the success of the commercial venture. After a brief review of the existing Spraberry literature, we will specifically address the ongoing and future work necessary to characterize the fracture network.
The Spraberry Trend Area was first developed in the early 1950's. P. 819
SPE and IADC Member
Maximizing project economics through reduced drilling and completion costs is a major industry goal that challenges us for innovative ideas and risk consideration. Presented is a case history of the application of dual tubingless completions for high pressure Wilcox formations that require fracture stimulation. Low cost modern approaches to design and selection of equipment and services as well as associated risks are discussed. The project area is located in a residential housing development in a major city and also penetrates a sensitive subsurface gas storage operation. The project was highly successful without any loss to safety or the environment.
Texaco Exploration and Production Inc. (TEPI) has been producing gas from deep Wilcox formations in the North Milton Field in Harris County, Texas (Figure 1) since the drilling of TEPI's first well in 1963. Most of the production has been from the L-2 Sand and deeper formations. The L-2 Sand occurs at a depth of approximately 13,000 ft, and TEPI has drilled to 18,000 ft in the North Milton Field in past years. Recent gas discoveries on offset properties at shallower depths focused attention to potential extension and development to TEPI properties. An evaluation by a team of TEPI exploration and drilling personnel determined the potential for five completion attempts to develop a narrow strip along the northwestern fringe of properties. Feasibility was dependent on low drilling and completion costs to achieve three completions to a depth of 10,500 ft and two completions to a depth of 12,500 ft.
A particular concern was the fact that the project area was located within the northwest city limits of Houston, Texas in the vicinity of Kuykendahl Road and Highway 1960 near the Intercontinental Airport. Over the years, residential housing development had encroached into the project area. Also, drilling would penetrate another operator's major underground gas storage reservoir. Selection of the drill sites and decisions relative to safety and the environment were extremely important.
Selection of Well Program
Offset operators were already using a relatively low cost single-well program approach as shown in Figure 2. For the 10,500-ft well, an 8-5/8 in. x 4-1/2 in. surface and production casing combination in 11 in. x 7-7/8 in. drilled hole, respectively, was being utilized. For the deeper 12,500-ft well, an 11-3/4 in. x 8-5/8 in. x 4-1/2 in. surface, intermediate, and production casing combination in 14-3/4 in. x 11 in. x 7-7/8 in. drilled hole, respectively, was being used.
The team chose a dual "tubingless" well program to further reduce costs. Therefore, only three wells were necessary to achieve the five desired completions. Two wells, Busch G/U #3 and Busch G/U #4 were drilled as straight holes to 12,500 ft and two parallel strings of 2-7/8 in. pipe were cemented in place as shown in Figure 3. One string of 2-7/8 in. was run to 12,500 ft for the deeper zone and the other string of 2-7/8 in. was run to 10,500 ft for the shallower zone. The third well, Sharman G/U 1 well 2 was drilled to 10,500 ft as a directional well and a single string of 4-1/2 in. casing was planned similar to offset operator's design.
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