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Offshore oil and gas field developments are capital-intensive projects that require extensive facilities to drill, produce and transport the hydrocarbon from the reservoir to the processing plant. Determining the site, number and size of these facilities are amongst the most important decisions impacting a project's success. Here, we present a novel strategy to assist in these decisions by combining a stochastic optimization routine with a Virtual Reality (VR) Aided Design. The model uses a discrete-network optimization algorithm that employs a Monte Carlo Markov chain to explore feasible configurations that minimize the development's investment. It integrates the optimization with a state-of-the-art VR environment to allow the engineer to both monitor the progress of the optimization and help guide the field development in real time.
We present results illustrating how the approach can be employed in field developments to connect well targets to processing facilities. The model determines the optimum location, size and number of offshore well-head platforms, tie-in facilities, well paths and pipeline routes. It incorporates critical technical considerations for the design of drilling paths (e.g. dog leg severity) and surface facilities (e.g. water depth). The model has been applied to real data from offshore field developments in the North Sea and the Gulf of Mexico. Results including the investment value and optimum configuration are shown and supplemented with graphics from the VR environment. The VR technology enables a novel approach to optimize the development. The immersive platform lets the user not only visualize the field, it is also capable of providing real-time interaction with the computer-generated design. This allows the integration of engineering intuition and experience to enhance the development and eliminate infeasible or unfavorable configurations.
This paper details the laboratory evaluation and product development for auniquely applied gas-lift paraffin inhibitor. Several crude oils, specific toone particular Gulf of Mexico subsea network, were characterized with respectto cloud point, pour point and paraffin content. This information was used todetermine suitable wax inhibitors to test for application into the productionfluids offshore. Cold finger wax deposition tests were performed to evaluateeight different inhibitor chemistries.
Details are given on the test methodologies used, with particular focus on thespecific evaluation to determine gas-lift suitability. Volatile flash analysiswas performed by a third party laboratory, coupled with a unique dynamicgas-lift test method, to find a suitable candidate. Of the products tested, twonew and specific formulations were developed for gas-lift applications thatdisplayed low weight loss and very little increase in viscosity.
There is very little documented in open literature on the formulations and testmethodologies employed to evaluate paraffin inhibitors for gas-liftapplication. This paper describes the most important treatment parameters anddetails on how gas-lift application was performed. This includes somesignificant learning lessons on the design and implementation of gas-liftparaffin inhibitors, as well as conclusions regarding the most appropriatedeployment parameters to avoid gunking and clogging of injection systems. Italso details the specific chemistries that can and should be used for this typeof application.
Barite sag is a well recognized, but poorly understood phenomenon in the drilling industry. Industry experts have offered a variety of measuring parameters, based upon empirical data that only partially correlate with the occurrence of barite sag. The development and introduction of robust, standardized well-site techniques to predict the onset of barite sag in dynamic flow has evaded the industry. The effect of shear rate and viscosity on dynamic barite sag has been studied and quantified using new and advanced technology. Changes in the potential for dynamic barite sag as a function of shear rate, hole angle, annular velocity and eccentricity correlate with ultra-low shear rate viscosity.
Field-proven technology has been developed to predict the potential for barite sag and to provide remedial measures through ultra-low shear rate viscosity modification. This technology was originally developed and validated in the field with invert-emulsion drilling fluids. Subsequent verification and validation work showed the technology was equally valid for water-based drilling fluids. This innovative technology is well-suited for use with a variety of commercially-available field viscometers and therefore lends itself towards wide-spread industry use. The paper will discuss the theoretical basis for this barite sag management technology and present the viscosity levels, with corresponding shear rates, required to manage dynamic barite sag. A case is made for use of this technology as an industry standard for barite sag management and is accompanied by full disclosure of the technology for peer review. Lastly, case histories are presented demonstrating the suitability of this technology in the field and ease-of-use at the well-site.
Cooper, C. (ChevronTexaco Energy Technology Co.) | Stear, J. (ChevronTexaco Energy Technology Co.) | Heideman, J. (ExxonMobil Upstream Research Co.) | Santala, M. (ExxonMobil Upstream Research Co.) | Forristall, G. (Forristall Ocean Engineering) | Driver, D. (BP America ) | Fourchy, P. (Murphy E&P Company)
Wisch, D. (ChevronTexaco Energy Technology Co.) | Stear, J. (ChevronTexaco Energy Technology Co.) | Versowsky, P. (ChevronTexaco North American Upstream, Inc.) | Welsch, J. (ChevronTexaco North American Upstream, Inc.) | Abadin, J. (ChevronTexaco North American Upstream, Inc.)
Kaufman, R.L. (ChevronTexaco) | Dashti, H. (Kuwait Inst. for Scientific Research) | Kabir, C.S. (ChevronTexaco) | Pederson, J.M. (ChevronTexaco) | Moon, M.S. (ChevronTexaco) | Quttainah, R. (Kuwait Oil Co.) | Al-Wael, H. (Kuwait Oil Co.)
This study reports reservoir geochemistry findings on the Greater Burgan field by a multidisciplinary, multiorganizational team. The major objectives were to determine if unique oil fingerprints could be identified for the major producing reservoirs and if oil fingerprinting could be used to identify wells with mixed production because of wellbore mechanical problems. Three potential reservoir geochemistry applications in the Burgan field are: (1) evaluation of vertical and lateral hydrocarbon continuity, (2) identification of production problems caused by leaky tubing strings or leaks behind casing, and (3) allocation of production to individual zones in commingled wells. Results from this study show that while oils from the major reservoir units are different from each other, the differences are small. Furthermore, a number of wells were identified in which mixed oils were produced because of previous mechanical problems. Both transient pressure testing and distributed pressure measurements provided corroborative evidence of some of these findings. Other data show that Third Burgan oils are different in the Burgan and Magwa sectors, suggesting a lack of communication across the central graben fault complex. This finding supports the geologic model for the ongoing reservoir simulation studies. Success of the geochemistry project has spawned enlargement of the study in both size and scope.
This paper will describe how the operator planned and drilled an eight-well sidetrack program, including one horizontal application, in Main Pass 299/144 field, Gulf of Mexico (GOM), in record time. This achievement was accomplished by improving operational efficiency (incident free) and reaching bottom hole objectives quickly, thus reducing open-hole exposure and costly "flat" time. The authors will discuss changes in the BHA, including mud motors, AKO settings, steerable ream while drilling tools and roller cone bits in addition to synthetic mud systems, that allowed each sidetrack operation to successfully drill oversize (eccentric technology) hole and hit the directional targets in record time.
The authors will discuss why different technologies were chosen and outline successful operations. A case study will be where a 7-5/8" steerable ream while drilling system with a 4-3/4" steel tooth pilot bit was able to build from 0° to 90° in one run, a record for the area.
Finally, the authors will document, with historical offset data, how improving operational efficiency and new bit technology reduced costs by approximately US$7.3 million on the eight-well program. Analysis will include a mechanical risk index that takes into account a variety of well variables to objectively compare costs on wells drilled in GOM.
The Main Pass 144/299 area is located approximately 100 miles southeast of New Orleans, Louisiana in the Gulf of Mexico in approximately 225 feet of water. Overburden consists of soft unconsolidated shales (gumbo) and Miocene reservoir sands. Production in the area is controlled by a large salt dome that acts to stratigraphically trap oil reserves. The first wells drilled in the area date back to 1962 with first commercial production established in 1967. The main focus in the field today is reentry projects to enhance production. The wells are drilled from jackup rigs cantilevered over the existing platforms. Most of the hydrocarbons in the area are produced through 2-3/8" or 2-7/8" tubing in 7" or 7-5/8" casing. The reentry wells are milled out of existing casing and vary from vertical to 20 degrees to horizontal. The producing sands are between 4000 ft to 10,000 ft TVD. The eight-well project utilized two jackup rigs drilling simultaneously, with each rig drilling four wells. The project (drilling & completion) was completed in approximately 67 days.
One of the most important aspects of improving drilling performance in the area was to document achievements as well as failures then objectively benchmark this data against the best in class. In mid 1999, the operator started to analyze offset drilling data in the GOM to compare its performance in Main Pass (MP) 299. Since complexity varies significantly from well to well, it was necessary to use an algorithm in an attempt to impartially compare one type operation against another. As a solution to this perplexing issue, engineers derived a Mechanical Risk Index (MRI). This mathematical computation takes into consideration, water depth (WD), measured depth (TD), kick off point (for sidetracks), true vertical depth (TVD) in addition to mud weight (MW) and horizontal displacement (HD) at TD. It also factors in the number of casing strings and several other drilling factors (DF) including "S" shaped well path, H2S or CO2 environment and the presence of hydrates or depleted sands with a differential greater than 3000 psi. Additional variable DF's include use of a subsea wellhead or mudline suspension system, if salt was penetrated or an open hole drilling size of less than 6-1/2" and/or if the well was horizontal. Although this method is not 100% accurate, it does help standardize well complexities for benchmarking purposes.
The growth of deviated and horizontal well drilling has limited the number of completion options that can be serviced by slickline units. Modifications to conventional slickline plugs, shifting tools, and setting tools have made it possible to run these tools on coiled tubing into highly deviated wellbores where push capabilities are required. Running and retrieval of gaslift valves, however, has remained the sole domain of slickline services. Declining reservoir pressures have more recently led operators to complete some of these high angle wells with gaslift systems fully realizing that not all of the mandrils will be accessible by conventional slickline units, instead requiring expensive rig workovers. By combining conventional slickline gaslift valve tools with coiled tubing and thorough, detailed job design, horizontal gaslift completions can now be economically worked over to optimise well production.
In the latter half of 1998 a major Gulf of Mexico operator was looking for alternatives to bring a highly deviated extended reach oil well back on line. Reservoir pressures had declined to the point that the original rig installed gaslift valve completion could no longer lift the well into production. Due to the deviation, a slickline unit could not access the dummy valves in the bottom three side pocket mandrils. Reservoir data indicated that there was sufficient oil in place to justify a workover to pull and rerun the completion. Aware that this type of application had been attempted with varying degrees of success in the past, a coiled tubing service provider in conjunction with a slickline service provider, proposed retrieving and running the valves pending the results of some yard trials. The subsequent success of this operation and the significant associated cost savings led to similar workovers for other Gulf of Mexico operators.
Operating limits for push and pull must be determined for mechanical manipulation or fishing activities when using coiled tubing to avoid exceeding the yield strength of the tubing. Building a model of the wellbore and simulating the workover activity allows the correct size, wall thickness, or material strength of coiled tubing string to be selected prior to mobilizing to the job. Run in and pick up weights during the initial trip into the well are compared with predictions from the Tubing Force Analysis in a coiled tubing software model in an effort to determine the maximum setdown and overpull available at the toolstring for each required depth. Figure 1 illustrates the simulated slackoff and pickup weights with the actual job data superimposed. This information is also critical in determining the correct way to configure downhole tools which rely on axial load (shear pins, jars), flow rate (hammers, orifi) or pressure (burst discs, jetting tools).
Coiled Tubing Equipment
After discussions with both the coiled tubing and wireline service providers, it was decided to use existing wireline kickover, pulling, and running tools. At present there are no field proven tools for accessing side pocket mandrils which are specifically designed for use on coiled tubing. The conventional OK-1 kickover tool is illustrated in Figure 2. The toolstring initially consisted of the following components: coiled tubing connector, check valve, hydraulic release tool, straight bar, knuckle joint, kickover tool, and valve pulling tool. A more detailed description can be found in Table 1. The 1.25" coiled tubing string was chosen over a 1.5" string because it was felt that the less stiff, smaller diameter string would provide more sensitive weight indicator readings while trying to manipulate tools in the side pocket mandrils.
Acidizing oil wells in sandstone formations often causes a variety of problems, ranging from inadequate productivity response, and unwanted stimulation of water, to the upsetting of surface separation facilities. A simple, economical, and effective change in the procedure for conducting these treatments involves displacing the oil from the zone to be acidized with a miscible gas, preferably CO2. Such displacement, often called preconditioning the formation, prevents interaction between the acid, its reaction products, and the resident oil. Field results with this treatment indicate an improved productivity response, less stimulation of water, and reduced emulsion separation problems at the surface.
Previously published information on this process was taken from a single field offshore Louisiana and involved the use of conventional mud acid (HF/HCl)1. The results in this paper demonstrate that the use of CO2 has wide applicability to offshore fields and works satisfactorily not only with conventional mud acids but with a variety of organic acids as well, is to inject into the formation a preflush, normally hydrochloric acid, to displace connate water and to remove the carbonates. In some cases, organic acids (either formic or acetic) are employed instead of HCl to avoid problems with the mineralogy of the formation. The second step involves injecting an HF-containing acid to react with clays, feldspars, and other materials thought to be the source of damage. The mixture most often employed is one of HCl and HF, although organic acids are sometimes substituted for HCl because of the sensitivity of certain formations to HCl.
This paper presents the results of two multiphase-pump trials. One field trial was conducted offshore on a platform in the Gulf of Mexico (GOM). It is a low pressure boost (100 psi) application involving gas lifted wells. The other field trial was conducted onshore in an oil field in Alberta, Canada. This multiphase pump was designed for a high pressure boost (850 psi) capability with primarily rod pumped wells feeding the suction of the pump.
The offshore pump was sized to handle the flow from one well. By lowering the back-pressure on the well, increased production was realized. The increased flow from one of the wells far surpassed the predicted quantity. Early problems with the double mechanical seal system were overcome and a new, simplified single mechanical seal system has been designed and installed.
The onshore multiphase pump clearly demonstrated that a twin screw pump can operate reliably in a field environment, even under severe slug flow conditions. The trial indicated that a considerable portion of the liquid in the recycle stream (required because of the high gas fraction of the multiphase fluid from the field) flashes into gas which occupies more volume in the pump than if it remained liquid. This decreased the capability of the pump to handle net flow from the field. These conditions motivated a re-evaluation of the pump sizing techniques.
Performance data and lessons learned information are presented for both field trials.
Multiphase fluid has been defined many different ways. In oil and gas production, the term two phase flow is used to describe a mixture of hydrocarbon liquid and hydrocarbon gas. If water is added as a separate immiscible phase, the system is described as three phase or multiphase flow.
Oil wells produce a mixture of oil, water, and gas, and occasionally sand, natural gas hydrates and waxes. The transfer of this mixture via a flow line to a central processing facility is called a multiphase production system. Since the inception of oil production, multiphase fluid has been transferred over short distances using reservoir energy. There was no device available to directly pressure boost the multiphase fluid when reservoir pressure was insufficient. The only feasible approach was to separate the phases and independently use a pump for the liquids and a compressor for the gases. The machine to perform that duty, the multiphase pump, has finally become a reality.
In late 1992, Chevron joined the Texaco Joint Industry Program (JIP) in which several types of multiphase pumps were tested in their Humble flow loop in Houston. This facility allowed hydrocarbon mixtures of oil, gas, and water to be measured and delivered to the pump suction for pressure boosting in any proportion desired. Test results were issued to the members.
Participating in this program allowed efforts to be focused in several ways. Based on the JIP results, Chevron decided to pursue twin screw positive displacement pumps instead of the other contenders like the hydrodynamic helical axial pump (born out of the Poseidon Joint Venture between Total, Statoil, and IFP - the French Petroleum Institute). Chevron also decided in late 1993 to procure two twin screw multiphase pumps for two field trial programs (one low pressure boost test, and one high pressure boost application). By running these pumps under actual field conditions, Chevron would gain the knowledge necessary to make an informed decision about the future of this technology and its application to Chevron assets. Additionally, operational experience would be gained by Chevron personnel.