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Abstract Asphaltic and sand production problems are common production challenges in the petroleum industry. Asphaltic problem results from the depositions of heavy material (asphaltene) in the vicinity of the well which may cause severe formation damage. Asphaltic materials are expected to deposit in all type of reservoirs. Sand production refers to the phenomenon of solid particles being produced together with the petroleum fluids. These two problems represent a major concern in oil and gas production systems either in the wellbore section or in the surface treatment facilities. Production data, well logging, laboratory testing, acoustic, intrusive sand monitoring devices, and analogy are different techniques used to predict sand production. This paper introduces a new technique to predict and quantify the skin factor resulting from asphaltene deposition and/or sand production using pressure transient analysis. Pressure behavior and flow regimes in the vicinity of horizontal wellbore are extremely influenced by this skin factor. Analytical models for predicting this problem and determining how many zones of the horizontal well that are affected by sand production or asphaltic deposition have been introduced in this study. These models have been derived based on the assumption that wellbore can be divided into multi-subsequent segments of producing and non-producing intervals. Producing intervals represent free flowing zones while non producing intervals represent zones where perforations are closed because of sand or asphaltic deposits. The effective length of the segments of a horizontal well where sand and/or asphaltene are significantly closing the perforations can be calculated either from the early radial or linear flow. Similarly, the effective length of the undamaged segments can be determined from these two flow regimes. The numbers of the damaged and undamaged zones can be calculated either from the intermediate radial (secondary radial) or linear flow if they are observed. If both flow regimes are not observed, the zones can be calculated using type curve matching technique. The paper will include the main type-curves, step-by-step procedure for interpreting the pressure test without using type curve matching technique when all necessary flow regimes are observed. A step-by-step procedure for analyzing pressure tests using the type-curve matching technique will also be presented. The procedure will be illustrated by several numerical examples.
- North America > United States (1.00)
- Asia (0.68)
- Europe > Norway (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
ABSTRACT Widening supply and demand gap in natural gas industry, the advent of tight gas policy and increasing interest of operators in tight gas sands and shale has opened new venues for development of unconventional plays in Pakistan. Middle Indus Basin hosts important gas fields of Pakistan. Most of the wells in this basin are completed in conventional lower Goru Sands. Lower Goru formation consists of inter-bedded sequences of sands and shale. Its unconventional sand and shale plays hold immense potential which has not yet been exploited due to lack of technology and promising economics. Moreover, Sembar shale is the well known source rock in this basin holding large shale gas potential. GIIP estimates for Lower Goru tight sands excluding the shale prospects are 8.4 TCF which are considered pessimistic due to lack of data in many fields. From the currently suspended or abandoned wellbores of the Middle Indus Basin, a pilot project needs to be defined in each of the fields, to prove the technical and economical feasibility of tight Gas Potential of the Basin. Commencement of production from unconventional sands will enhance the production in a cost effective manner due to availability of infrastructure and facilities. This paper focuses on the utilization of existing wellbores as well as data set and highlighting additional data acquisition requirements coupled with completion and multi-stage fracturing techniques for designing a pilot project. Case study of a pilot project in one of the fields of this basin is discussed. It encompasses the basic workflow, candidate selection criterion, Geo-mechanics, sector modeling, hydraulic fracture design and risk evaluation coupled with its use in full field development projects.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Asia > Pakistan > Sindh > Lower Indus Basin > Goru Formation (0.99)
- Asia > Pakistan > Sindh > Khairpur District > Indus Basin > Kadanwari Field (0.99)
- Asia > Pakistan > Sindh > Sanghar District > Sembar Formation (0.98)
Abstract The US Gulf of Mexico is one of the few regions in the world where wells are completed in the deepwater Miocene and Lower Tertiary reservoirs. These deepwater plays have required constant technological improvement to equipment service capabilities in order to maintain integrity in the 30,000-psi environments and minimize risks. Although capable tools and guns have been developed, continuous assessment of reliability still remains vital in the exploratory processes. Testing for production analysis in deep and ultra-deep water is critical, and when target reservoirs produce heavy oil, gas and condensate, or are in HP/HT environments, planning safe tests with risk mitigation that can gather high-quality data is paramount. Because of the high rig rates for deep-water operations, prolonged periods of low temperature and heat loss that can affect production or enable hydrate formation and other environmental challenges cannot be ignored. Fluid volumes and water depths can increase well-control time and expense. Also, since well tests are conducted from mobile vessels, alarm and subsea equipment philosophies are critical to success, and well-test string configurations must be flexible yet control well safety. Obviously, all issues must be understood for the program plan to anticipate the potential challenges. The purpose of this paper is to explore these issues as well as discuss mitigation methodologies. The considerations, merits, and limitations of various solutions will be considered. Lessons learned from actual cases will compare the consequences of inadequate preparation to the benefits of proper design. This paper explains why and how the methods and equipment suggested should be used and will include: DP vessel testing Well integrity at extreme depths and pressures Functional pressure-operated tool windows Coiled tubing Cushion and mud-type criteria Hydrate prevention Perforating strategies.
- North America > United States (1.00)
- South America (0.93)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
Abstract The first hydraulically operated completion was installed in Australia in 2004 (Guatelli et al 2004). Since then, a number of intelligent completions have been installed in offshore Australia. The remoteness of offshore Australia, particularly in the Timor Sea area, means intervention vessels are not readily available and well interventions are costly operations. For this reason, intelligent completion is considered to be an attractive alternative, by providing a down-hole solution to actively manage the reservoir production life and delay potential water breakthrough. The Kitan oil field is remotely located in the Joint Petroleum Development Area (JPDA) between East Timor and Australia. The Kitan oil field production facilities consist of three vertical producing wells, subsea flowlines, risers, and one Floating Production Storage and Offloading (FPSO) facility. The wells were completed with an intelligent design and cleaned up using a rig before the FPSO arrived on location. The intelligent completion design consists of two multi-stage hydraulic down-hole Flow Control Valves (FCVs) and three Down-Hole Gauges (DHGs) to independently control and monitor two different production zones. The FCVs have a total of 8 positions (fully opened, fully closed and 6 intermediate choke positions). It is planned to close the lower FCV to shut off water production from the lower zone while the upper FCV remains fully opened over the field life. The different FCV choke positions were utilized during the field startup and during the early stages of production while the water cut was still low, to overcome unforeseen technical limitations in the production system, and to optimize hydrocarbon production. This paper describes various aspects of the Kitan oil field intelligent well completion from design through installation and field startup to early stage of production operations, and includes technical problems encountered during the field startup as well as lessons learnt.
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > Kitan Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Block WA-315-P > Plover Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Block WA-274-P > Plover Formation (0.99)
- Oceania > Australia > Timor Sea > Bonaparte Basin > Kitan Field (0.99)
Abstract Well productivity decline in mature gas fields, often attributed to liquid loading, may actually be due to salt deposition, which can produce identical symptoms. Salt plugging in gas wells has been well documented in Germany and the USA and is increasingly becoming an issue in the North Sea. There is an increasing awareness amongst North Sea operators of the issue of salt precipitation in gas wells, however, a recent literature search on the subject revealed a limited body of work suitable for use as an introduction to the subject. This paper reviews the mechanisms of salt precipitation, and looks at some modelling and monitoring methods and reviews the available remediation techniques Salt problems occur over a very limited range of producing conditions and are generally seen in mature, depleted gas fields, explaining perhaps the recent increasing interest in the issue amongst North Sea operators (UK and Netherlands). Salt solubility in water decreases with both reducing pressure and temperature, such as in a producing gas well, so that salt can precipitates as saturated produced water flows up the wellbore. The solubility effects are small but are exacerbated, or exceeded, by dehydration effects as produced water enters the wellbore. Salt may precipitate and adhere to the completion walls and produce a salt bridge. Salt can plug perforation tunnels and even form within the reservoir itself. It is not solely a downhole problem, salt precipitation can occur inside surface equipment such as compressors. For production operations, early detection or prediction of salt precipitation is vital, yet it has proved difficult as the issue depends on individual well conditions. The paper discusses how diagnostic modelling may help if certain data are available: produced water salinity, operating conditions along the wellbore and reliable WGR history. Finally, the paper describes current remediation techniques to restore gas well productivity.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.94)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (0.93)
- (6 more...)
Abstract Production analysis can aid in the determination of formation and stimulation characteristics including permeability, fracture half length, fracture conductivity, and completion efficiency. The time to the end of the infinite acting linear flow combined with the distance between stimulated fracture faces yields permeability. The production analysis method includes three flow regimes; infinite acting linear flow, fracture-fracture interference from evenly spaced fracture stimulation treatments which leads to boundary dominated flow and fracture-fracture interference when fracture stimulation treatments are unevenly spaced. Production for the uneven or non-uniform spacing situation can provide perforation cluster completion efficiency for plug and perf completions and can be diagnostic in packer ports systems when stimulations are originated at the packer due to packer induced rock failure. Low completion efficiencies could dictate fewer clusters per stage in future designs. If low completion efficiencies are revealed, increased isolation to maintain actual stimulated fracture face distance may be required. In packer port systems identification of non-design uneven spacing may also warrant increased isolation. Case studies from three shale reservoirs are included to illustrate the production analysis techniques.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.65)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The US Gulf of Mexico is one of the few regions in the world where wells are completed in the deepwater Miocene and Lower Tertiary reservoirs. These deepwater plays have required constant technological improvement to equipment service capabilities in order to maintain integrity in the 30,000-psi environments and minimize risks. Although capable tools and guns have been developed, continuous assessing of reliability still remains vital in the exploratory processes. Testing for production assessment in deep and ultra-deep water is critical, and when target reservoirs produce heavy oil, gas and condensate, or are in HP/HT environments, planning safe tests with risk mitigation that can gather high-quality data is paramount. Because of the high rig rates for deep-water operations, prolonged periods of low temperature and heat loss that can affect production or enable hydrate formation and other environmental challenges cannot be ignored. Fluid volumes and water depths can increase well-control time and expense. Also, since well tests are conducted from mobile vessels, alarm and subsea equipment philosophies are critical to success, and well-test string configurations must be flexible yet control well safety. Obviously, all issues must be understood for the program plan to anticipate the potential challenges. The purpose of this paper is to explore these issues as well as discuss mitigation methodologies. The considerations, merits, and limitations of various solutions will be considered. Lessons learned from actual cases will compare the consequences of inadequate preparation to the benefits of proper design. This paper explains why and how the methods and equipment suggested should be used and will include: DP vessel testing Well integrity at extreme depths and pressures Functional pressure-operated tool windows Coiled tubing Cushion and mud-type criteria Hydrate prevention Perforating strategies.
- North America > United States (1.00)
- South America (0.93)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
Abstract Declining reservoir pressure and rate in the Jonah field has led to the common problem of liquid loading. As fluids accumulate the downhole pressure increases which decreases the available drawdown that allows fluids to flow into a wellbore. Jonah wells are completed in the 2000 - 3500-ft thick Lance Formation, using 8-16 hydraulic fracturing stages. With initial end of tubing (EOT) depths set above the top perforation for most wells, this left approximately 1500-3000 feet (gross pay) of perforations below the EOT. With lifting velocities significantly greater in larger diameter casing than tubing, a liquid column was developing below the EOT and engineering and operational attention was needed to improve field performance. Improving on the operational efficiency involved the implementation of recommended actions from a cross-functional well by well review group that received input and support from all Jonah asset members. The approach focused on how to improve liquid removal and optimize gas production from wells identified as liquid-loaded. In addition to installing plunger lift systems and injecting soaps, in 2008 a program was started to lower production tubing in wells by approximately 50-70% into perforations; the purpose was to reduce the column of fluid in the wellbore by helping more efficiently unload fluids using the reduced critical flow rate in the tubing and allowing plungers deeper access to the column of liquid covering the perforated interval. This paper discusses the results of lowering the EOT of over 100 gas producing wells in the Jonah field. The wells showed an average sustained uplift of approximately 105 mcfd, with undiscounted payout of less than 12 months. In addition, on wells that have had the tubing lowered, their decline curves appear to flatten out, offsetting anticipated double digit decline. Practical methods of selecting candidate wells and the new EOT are presented and discussed.
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Plunger lift (1.00)
- (3 more...)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 147247, ’Successful Discovery of Light Oil From an Unsuccessful Paleozoic Well Through Re-Entry - A Case Study of an HP/HT Well,’ by Haifa Al-Bader, SPE, Yousef Zaid Al-Salali, SPE, Vidya Sagar Duggirala, SPE, A. Manimaran, and S. Packirisamy, SPE, KOC, prepared for the SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November 2011. The paper has not been peer reviewed. An exploratory well, the second deepest in Kuwait, had been drilled in the Mutriba field to 22,094 ft. Two formations, Kra-Almaru and Khuff, were perforated and tested. The tests revealed the presence of sparse gas, and it was decided to test and complete this well in the Jurassic formation through re-entry. The re-entry in this ultradeep well was full of challenges; however, by overcoming all the challenges, this well was successfully perforated, stimulated, and tested, which led to the first commercial discovery of oil and gas within the Jurassic reservoir in the Mutriba field. Introduction Two zones in Paleozoic and Triassic sections were perforated and tested separately to evaluate the presence of hydrocarbon between 18,500 and 21,500 ft. The well was completed in 2004. After undesirable results were obtained from the Triassic and Paleozoic formations, exploration teams studied the feasibility of testing Jurassic formations in this well through re-entry. Testing Jurassic formations in the Mutriba field from an existing well will be more economical than drilling a new well. A snubbing unit was deployed in 2008. In 2009, a suitable workover rig was deployed to test Jurassic formations in this previously drilled well. The location of the Mutriba field is shown in Fig. 1. A snubbing unit had been used to isolate the open perforations of the Triassic zone with cement. Subsequently, a workover rig was deployed to test the prospect of a Jurassic reservoir. Testing the Jurassic reservoir behind two heavy-walled casings (7 in. 46.4 lbm/ft and 8⅝ in. 40 lbm/ft) combined with extreme sour and high-pressure/high-temperature (HP/HT) conditions warranted high health, safety, environment, and technical precautions. Challenges for re-entry to this well included HP/HT conditions, a high surface pressure, and well-killing issues. Testing of the formation fluid revealed the presence of an unexpectedly high concentration of H2S (20%) and CO2 (2%), which presented challenges for coiled-tubing (CT) operations, stimulation, flowing the well, and fluid disposal.
- Asia > Middle East > Kuwait > Northwest Kuwait (0.87)
- Asia > Middle East > Israel > Haifa District > Haifa (0.25)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Abstract Hydraulic fracture design is an example of what is largely a manual process that requires interaction with a number of different software applications to obtain fracture geometry, production constraints, production sensitivity criteria, and NPV scenarios. When the goal is an optimized fracture design, the process is especially onerous, as it requires iterative interactions with reservoir simulators, nodal programs, economics models, drilling-well design systems, and stimulation design tools to arrive at a suitable design. Previous papers have detailed the benefits that can be derived from the automation of operations, engineering workflows, and production workflows in general. A major service company was able to quickly provide workflow automation benefits to an East Texas field with the aid of its workflow automation software. In the East Texas field, the service company was able to preserve the provided business service, yet change many of the connections with other software applications that were used to deliver the business benefit, as well as the engineering methods used to optimize the design. The GoM Lower Tertiary Wilcox Sand Field was also deemed a good candidate by a major service company to operational and production workflow automation, given its low PI, high-cost wells, HPHT tech challenges, and production uncertainty. This fracture workflow uses a unique holistic combination of tools, which are coupled in a way as to reflect the actual economic values of various fracture scenarios. With the Microsoft Upstream Reference Architecture (MURA) initiative, Microsoft, along with several of its E&P partners, prescribes this approach, which focuses on achieving a level of interoperability between software solutions used by the industry.
- North America > United States > Texas > Upshur County (0.45)
- North America > United States > Texas > Smith County (0.45)
- North America > United States > Texas > Rusk County (0.45)
- (2 more...)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.99)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Play > Wilcox Play Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Play > Wilcox Play Formation (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin > Wilcox Trend Formation (0.99)