Sidetrack Wells Research Articles

The Messinian reservoir in El-Tamad oil field, Nile Delta, Egypt: Seismic interpretation and 3D modeling

El-Tamad Field, the first oil discovery in the onshore Nile Delta, is one of the promising areas in the Nile Delta for oil and gas. Therefore, thirty seismic lines, core data, and real-time flowline resistivity measurements of the Messinian Qawasim Formation were analyzed to characterize and model the reservoir in El-Tamad Field. The structure model shows that there are three main faults in the investigated area; F1 fault is a major growth fault trending E-W with a downthrown to the north, F2 trending NW-SE with a downthrown northeast, and the NE-SW trending F3 fault with a downthrown southeast. The depth-structure contour map on the reservoir's top shows that there is a rollover anticline fold formed at the downthrown side of the major growth fault. The petrophysical model illustrates that effective porosity increases towards both of southeastern and southwestern parts, while water saturation decreases in the southeastern part of the field, and the net-to-gross increase towards the center. Penetrating more vertical and sidetrack wells along the line connecting wells 1, 3, and 4 in El-Tamad Field, especially in the crest of the anticline fold that was recorded in the area is highly recomended. The spatial variation of the reservoir quality was attributed to the depositional setting, where many branches of larger distributary channels (sand facies) accumulated within a muddy estuary (shale facies) on the front of a bay-head delta.

REHABILITATION OF DECOMMISSIONED WELLS

This article is devoted to the return of decommissioned wells to sidetracking operations by drilling a secondary wellbore away from an original wellbore. First of all, the relevance of the work is justified in the introduction with indicators of the application of this method. It describes how the problem is formed and the steps taken to solve it. The steps on how to carry out the process using techniques and technology are listed. In conclusion, the main results of this work are given. Keywords: rehabilitation of the decommissioned wells, directional drilling, sidetrack wells, decommissioning of the oil fields, multilateral drilling

Eccentric array-based borehole transient electromagnetic system for NDT of multipipe strings in sidetrack well

In the middle and late stage of oilfield development, the sidetracking technology is widely used for restoring the production of stripper well, damaged well and abandoned well. In this paper, we present an eccentric array-based borehole transient electromagnetic (TEM) system for nondestructive testing (NDT) of multipipe strings in sidetrack well. Using the borehole TEM signal model, the response of eccentric sensor is analyzed, which contains more information in the direction of eccentricity. On this basis, multiple eccentric sensors with different depths and different angles are utilized to form an eccentric array, which can be used to determine the direction of sidetracking and to detect the multiple pipes in hanging casing strings. The performance of the proposed system was verified by applying it to sidetrack wells in Shengli oilfield. In addition, field experiments were conducted, and the results demonstrated the effectiveness of the proposed method.

Прогноз емкостных свойств пород по данным буровой механики в процессе роторного бурения скважин с горизонтальным окончанием

Прогноз емкостных свойств пород по данным буровой механики в процессе роторного бурения скважин с горизонтальным окончанием

Первые результаты бурения боковых горизонтальных стволов на пласты тюменской свиты Красноленинского месторождения

Первые результаты бурения боковых горизонтальных стволов на пласты тюменской свиты Красноленинского месторождения

Applying the hydrodynamic model to optimize the production for crystalline basement reservoir, X field, Cuu Long Basin, Vietnam

Weathered and fractured crystalline basement is known as the important unconventional reservoir in the Cuu Long Basin. Naturally fractured reservoir plays a crucial role in oil exploration to contribute for hydrocarbon production in Vietnam. However, the complexity and heterogeneity of the fractures system in the basement reservoir are challenges for oil and gas production. They require the realistic simulation scenarios to estimate the hydrocarbon potential as well as field development plan of these reservoirs. Thus, this paper aims to propose the feasibility development scenarios to improve oil recovery factor for crystalline basement reservoir, X field, Cuu Long Basin, Vietnam. First, history matching process is validated for the model to fit the actual production data (reservoir pressure, pressure, water cut in each well) in order to approach closer the fluid flow behavior through the reservoir. The manual matching was selected to adjust the actual aquifer size and permeability distribution with limit simulation runs. Next, the highest reliability matching model which approximately reflects the actual fluid flow behavior can be used as the base case to forecast the future reservoir performance through the field development plan. The most potential scenario is to add six new infill production wells, two side track wells and two water injection wells. The forecasted results indicate that this scenario yields 8% more oil recovery factor compared to the natural drive with thirteen producers. This result suggests that the precise field development plan is to increase the efficiency of the production process by increasing the displacement parameters of residual oil and reservoir sweep efficiency by stimulation. The major contribution of this paper demonstrates the merits of the field development plan in fractured basement reservoir. The findings of this study can help better understand the fluid flow behavior using the production history profiles and field development scenarios of crystalline basement reservoir of Cuu Long Basin.

Разработка методики оценки коэффициента продуктивности по нефти скважин с боковым стволом (на примере бобриковской залежи Уньвинского месторождения)

Разработка методики оценки коэффициента продуктивности по нефти скважин с боковым стволом (на примере бобриковской залежи Уньвинского месторождения)

Integrating Managed-Pressure Drilling Into HP/HT-Well Planning

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188335, “Integrating Managed-Pressure Drilling Into HP/HT-Well Planning,” by Michael Cadd, Lewis Steven, and Robert Graham, Shell; Fedderik van der Bos, Nederlandse Aardolie Maatschappij; Craig Leggett, Blade Energy Partners; and Emil Stoian, Weatherford, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Managed-pressure drilling (MPD) is an increasingly common technique in narrow-margin high-pressure/high-temperature (HP/HT) wells. However, MPD is sometimes viewed as a bolt-on technology, only added after much of the planning work has been carried out and all other alternatives have been exhausted. The decision to use MPD should be made at the earliest stage of well planning. An early commitment to integrate MPD into an HP/HT drilling operation can make MPD more than just an enabling tool and turn it into a performance tool that offers significant operational benefits. Overview Project 1. For an HP/HT field redevelopment in the UK North Sea, seven side-track wells were drilled from a jack-up over an existing platform. MPD was used from the beginning, but the full benefits of MPD were not realized until later in the project. MPD was initially included to hold surface backpressure (SBP) across two connections to mitigate borehole-stability risk in an un stable shale. However, once the system was operational, further benefits continued to be identified and the scope of MPD operations grew significantly. At the same time, more knowledge of the subsurface was being gained, and it became clear that some of the planned wells would not be drillable without MPD because of a significantly reduced drilling window in the overburden. MPD became a key part of the design philosophy for later wells, where managed-pressure techniques were used to set and cement casings significantly deeper than would have been possible conventionally. MPD successfully mitigated classical HP/HT issues so that problems with losses and gains, handling of elevated gas levels, and mud-weight-selection issues were all virtually eliminated. Project 2. For a standalone HP/HT exploration well drilled from a jack-up offshore the Netherlands, MPD was initially selected because of the extremely narrow margins between the pore and fracture pressures in the 8½- and 6-in. sections. Conventional drilling would not have been possible without inducing losses and spending significant time circulating to adjust mud weights, as seen in a key offset well. Taking advantage of the learnings from Project 1, MPD was selected at an early stage of the planning process and was fully integrated into the well design and operations. Mud weight, drilling parameters, and bottomhole-assembly design were all tailored to suit MPD operations. Integrated HP/HT and MPD procedures were developed on the basis of traditional HP/HT techniques but were modified to make full use of the additional functionality provided by MPD. A combined HP/HT and MPD training course was developed, and key personnel were trained in HP/HT and MPD techniques. Rig modifications were made well in advance, and MPD was implemented one hole section earlier than required to familiarize all crews with the new equipment and procedures. The result was a potentially extremely challenging well that was drilled without any of the conventional HP/HT problems observed in the offset wells.

Применение устройств контроля притока в боковых горизонтальных стволах скважин пласта АВ4-5 Самотлорского месторождения

Применение устройств контроля притока в боковых горизонтальных стволах скважин пласта АВ4-5 Самотлорского месторождения

Real-Time Reservoir Management in a High-Cost Deepwater Environment - Greater Plutonio

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 128542, ’Greater Plutonio - Real-Time Reservoir Man age - ment in a High-Cost Deepwater En vironment,’ by Dave Booth, SPE, and Pedro Sebastiao, SPE, BP plc, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. The paper has not been peer reviewed. Greater Plutonio is a large subsea development with a planned first phase of 43 high-rate subsea wells. A relatively low level of classical field appraisal was performed because of high costs. Innovative subsurface management was required to reduce substantial uncertainty during the development phase. Remote access to real-time data enabled making better decisions faster and reducing the number of field staff. Introduction The Greater Plutonio fields (Plutonio, Cobalto, Galio, Cromio, and Paladio) were discovered offshore Angola between 1999 and 2000 and are Upper Oligocene turbidite reservoirs. Changes in fluid and lithology in the semiconsolidated reservoir rocks manifest themselves as distinct changes in seismic response. Water depths are between 1200 and 1400 m, and a relatively dispersed resource base resulted in the most viable development concept being a 100% subsea-well development with multikilometer-scale well spacing produced through a large floating production, storage, and offloading (FPSO) vessel. The initial development phase of 43 wells, plus up to 25 additional infill and sidetrack wells, was the largest subsea development undertaken by the operator. Of the initial 43 wells, 23 are injection wells, and most are completed across multiple reservoirs with full sand control. At the time of writing this paper, 34 wells had been drilled, and subsurface outcome was largely as expected. All reservoirs are waterflooded, with approximately one-half the injection wells having downhole flow control (DHFC) to improve injection management. The high-porosity rocks often have permeability exceeding 1 darcy, which, combined with high-gravity oil, provide a favorable mobility ratio and very efficient displacement. Recovery factors in some reservoirs should exceed 50%. The associated gas is injected through two wells in the Plutonio field to provide pressure support. This process will continue for 3 to 4 years after field startup, until gas export is available after commissioning of the Angola liquefied-natural-gas project. All of the production wells have openhole-gravel-pack (OHGP) completions, some with openhole completion lengths of up to 800 m. Although confidence to sanction the project was provided by the high-quality seismic data, a high degree of subsurface uncertainty remained (e.g., reservoir connectivity). Appraisal drilling was conducted in only one of the five fields. Therefore, a significant amount of subsurface appraisal was loaded into the development stage. The understanding and management of subsurface uncertainty has been crucial for the development, with early and effective data collection by use of wireline, logging-while-drilling (LWD), and coring programs; preproduction well-interference testing; and real-time data acquisition during the ramp-up period.

The Jasmine discovery, Central North Sea, UKCS

Abstract The Jasmine Field is located in blocks 30/06 and 30/07a on the J Ridge, the southeastern extension of the Forties–Montrose High, which separates the eastern and western basins of the UK Central North Sea. The field was discovered in 2006 and is close to two ConocoPhillips producing fields, Jade and Judy, which serve as useful local analogues. The main West Limb structure is a turtle-back faulted anticline NW of the Joanne salt pillow. The primary reservoir is Triassic in age and consists of stacked fluvial sandstones of the Joanne Member of the Skagerrak Formation. The HPHT exploration wells 30/06-6 and geological sidetrack 30/06-6Z discovered a rich gas condensate column of 2300 ft, some 1100 ft deeper than the mapped independent structural closure of the prospect, and achieved good flow rates on test. To appraise the discovery and assess the potential for significant additional volumes in an adjacent downfaulted terrace, a programme comprising a main well and two sidetrack wells was initiated in 2007. Appraisal well 30/06-7 discovered a 550 ft hydrocarbon column in the Northern Terrace with a hydrocarbon–water contact shallower than that observed in the West Limb, thereby proving structural compartmentalization between the two fault blocks. Good flow rates were achieved from a drill stem test in mechanical sidetrack well 30/06-7Z. Sidetracks 30/06-7Y and 30/06-7X were drilled to confirm the northwestern extension of the West Limb discovery and to test the northern extent of the Northern Terrace accumulation, respectively. This programme has reduced volumetric uncertainty but the trapping mechanism and the ultimate extent of the Jasmine accumulation remain unknown. Comprehensive data acquisition throughout the exploration and appraisal phases, including drill stem testing, core recovery and seismic data reprocessing, has facilitated a detailed reservoir characterization programme. Jasmine represents a significant new high pressure/high temperature resource in the mature Central North Sea and is currently undergoing development planning.

A Tool for Liner Running and Cementing Using Electric-Line Coiled Tubing

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 120992, "The Side Exhaust Liner-Running Tool: A Tool for Liner Running and Cementing Using E-Line Coiled Tubing," by Greg Sarber, SPE, and Mark Johnson, SPE, BPXA; Bob Harris, SPE, and Carl Diller, Northern Solutions; and John Milne and Alan Holloway, Baker Hughes, originally prepared for the 2009 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 31 March-1 April. The paper has not been peer reviewed. A new system for running and cementing liners using electric-line coiled tubing (CT) has been proved on the North Slope of Alaska. The side-exhaust liner-running tool (SELRT) provides the functionality to run and release a liner while using a liner wiper-plug (LWP) system to ensure good cement quality. A jointed-pipe liner is conveyed and cemented with the CT containing an electric umbilical. This innovative equipment has proved to be a substantial health, safety, and environment (HSE) benefit and yields savings in rig time. Introduction There has been a continuous CT-drilling (CTD) campaign on the North Slope of Alaska since 1994. This program re-enters existing vertical wells and drills horizontal sidetracks in the Prudhoe Bay, Kuparuk, Endicott, and Milne Point fields. These sidetracks typically are drilled through 4 1/2-in. production tubing without pulling the tubing or removing the existing production tree. More than 575 new sidetrack wells have been drilled in these fields since 1994. Before 2001, conventional 2 3/8-in.-outside-diameter CT (electric-line-umbilical free) was in use. When a well reached total depth (TD), the typical completion was a solid/cemented liner followed by CT-conveyed perforating guns. The liner-running tool used a ball-drop system to release the liner and a CT dart/LWP system to ensure that uncontaminated cement was placed accurately behind the liner. This system proved quite reliable and robust and accounted for the majority of wells drilled up to 2001. In 2001, a new measurement-while-drilling (MWD) bottomhole assembly (BHA) was tested. To operate, this BHA required an electrical umbilical inside the CT. This drilling system provided higher data-telemetry rates, more real-time downhole information, and better directional control using an electrical downhole orienter instead of a mechanical orienter. This system proved to be especially beneficial in managed-pressure- and underbalanced-drilling (MPD and UBD) applications. The electric orienter minimized shale damage by eliminating the pump cycles needed to operate a mechanical orienter. This new equipment provided sufficient time savings to enable a 30% increase in effective rate of penetration. Unfortunately, some of the productivity gains realized from using the electric-line CT BHA were lost when it came to completing the wells. To run and cement the liner, the CT reel containing the electric line had to be replaced with an electric-line-free reel to use the existing liner-running equipment. Reel swaps are an HSE risk when conducted in the middle of drilling operations, especially when conducted in Arctic winter conditions; the reel exchange consumed some of the time-savings benefits of using the new drilling BHA, additional operating costs were required to inventory two types of CT, and exchanging reels caused a delay from when the well reached TD until the liner was on bottom.

Redevelopment of a Matured Multilayered Carbonate Offshore Field Through High-Technology Horizontal and Multilateral Wells

Summary Oil productivity from Mumbai High field, an offshore multilayered carbonate reservoir, increased significantly through the implementation of a major redevelopment program. Geoscientific information available from approximately 700 exploratory and development wells drilled in the field during nearly 25 years was incorporated during geological and reservoir simulation modeling of the field. High-technology drilling (viz. horizontal/multilaterals for the new development wells) was adopted on field scale to effectively address typical complexity of the layered carbonate reservoirs. Since the commencement of the project in 2000, approximately 140 new wells were drilled, mostly with horizontal and multilateral drainholes. Besides these, more than 70 suboptimal producers were also converted as horizontal sidetracks under brownfield development. The horizontal sidetracks were drilled as long-drift sidetrack (LDST), extended-reach drilling (ERD), LDST-ERD, short-drift sidetrack (SDST), and medium-radius drainhole (MRDH) types of wells through the application of innovative and emerging drilling technologies with nondamaging drilling fluids, whipstocks to kick off sidetrack wells, rotary-steering systems, and expandable tubulars to complete horizontal sidetracks in lower layers. With the implementation of this project, the declining trend was fully arrested and a significant upward trend in production has been established.

First TTRD Well Drilled From a Floating Platform - Concept Study to Reality

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98880, "World's First TTRD Well Drilled From a Floating Platform in the Njord Field, North Sea - From Concept Study to Reality," by T. Flatekvaal, SPE, Hydro E&P; E. Saeverhagen, SPE, O.E. Eng, SPE, and N. Jepson, SPE, Baker Hughes Inteq; J. Oyovwevotu, SPE, Leading Edge Advantage; and J.F. Namtvedt, SPE, and M.M. Price, SPE, Hughes Christensen, prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February. The full-length paper describes the concept study, preplanning, and drilling of the world's first through-tubing rotary (TTR) -drilled well drilled from a floating platform. The full-length paper details the challenges of maintaining the integrity of the existing subsea well completion together with the specific bottomhole-assembly (BHA) requirements to drill in this highly depleted reservoir. Introduction The Hydro-operated Njord field is approximately 130 km northwest of Kristiansund and 30 km west of the Draugen field in 350 m of water in the North Sea, and is being developed from a floating steel platform (Njord A). Production began in 1997, but the field already is mature with a rapidly declining oil production. Oil production currently is approximately 35,000 B/D from eight oil producers; associated gas is injected into four gas injectors. Infill drilling is the most important (promising) measure to increase oil recovery. The reservoir is very complex with numerous faults and unconnected reservoir segments. In May 2005, Well 6407/7-A-9 AH was drilled as a test well and technical-qualification well for a possible TTR-drilling (TTRD) campaign in Njord. Well A-9 AH proved that the concept of sidetracking from existing wells without retrieving the existing completion and horizontal Christmas tree was feasible from a floating platform with conventional rig equipment. Feasibility Study The Njord petroleum technology department established a task force to evaluate all wells for possible sidetrack candidates. Evaluation showed that drilling ordinary sidetrack wells would not be economical because abandonment of existing producing wells would leave behind unproduced reserves, and the cost of retrieving the existing completion string including the horizontal Christmas tree would be too high to be cost-effective because of the marginal additional reserves in each new target. Compared to TTRD operations from fixed platforms, the following technical challenges had to be resolved to drill subsea TTRD wells from the floating Njord platformDamage to the existing completion string, including the horizontal Christmas tree, the seal areas for the tubing-hanger barrier plug, and the internal tree cap.The influence of rig dynamics, including heave, pitch, and roll on wear on the existing well completion.Damage to the tubing downhole safety valve (DHSV) at 850 m.Effect of rig heave on swab and surge in wells with small inside-diameter (ID)/outside-diameter tolerances and on depletion-induced weak formations.Required annular velocity in the marine riser to avoid critical accumulation of cuttings in the 19-in.-ID marine riser and subsea blowout preventer (BOP).Mud rheology effects resulting from mud cooling in the 360-m marine riser.Well-control issues because it was impractical to trip into the well through the subsea-BOP annular preventer.Increased focus on early kick detection because of the marginal well volume underneath the subsea-BOP stack.

Three-dimensional structural modeling and its application for development of the El Portón field, Argentina

The El Portn field, located in the Neuqun basin, belongs to one of the largest oil and gas trends of Argentina. Fields in the area produce oil from middle Cretaceous fluvial and eolian porous sandstones at about 600 m (1968 ft) below sea level. The field structure is described as a triangle zone located in front of the Neuqun fold and thrust belt that was formed during the Andean orogeny by a combination of tight detachment folds and fault-propagation folding. The structure has a basal detachment through the contact between the evaporites of the Auquilco Formation and the shales of the Vaca Muerta Formation. The upper detachment corresponds to the salt layers of the Huitrn Formation. The structure was reactivated by basement fault inversion that produced tightening of the preexisting geometry and backthrusts that increased the structural complexity. A three-dimensional (3-D) structural model has been constructed using 3-D seismic data and well information to plan new horizontal wells in steeply dipping to overturned limbs, through 50–60 m (164–196 ft) of productive reservoir avoiding pilot and sidetrack wells. The results of the modeling have made the company consider as a priority the 3-D structural model-building procedure for the development of fields located in fold and thrust belts.