Amari, Mustafa (Schlumberger) | Misherghi, Nasser Ali (Schlumberger) | Algdamsi, Hossein Ali (Schlumberger) | Sharaf, Hosam Eldin Mohamed (Schlumberger) | Abid, Mohamed (Schlumberger) | Porturas, Francisco (Schlumberger) | Zeglam, Adel (Mellitah Oil & Gas B.V Libya) | Jalool, Hassan (Mellitah Oil & Gas B.V Libya)
With the advances made in drilling long horizontal wells over the past decades it has become economically attractive to produce oil from thin oil rims. However, the production from these types of reservoirs presents several challenges. Gas coning is one of the most important ones. Horizontal well drilling traditionally helps to improve the oil recovery and avoid problems of premature gas/water breakthrough. In Bouri field, offshore Libya, the main concern of the operator was to establish an advanced method of controlling gas and water encroachment in a fractured carbonate reservoir characterized by high vertical permeability. This paper describes the first Inflow Control Device (ICD) installation for Mellitah Oil & Gas, and the first such application in Libya Offshore field. It was an integral part of a well completion aimed at evenly distributing inflow in a horizontal well, and at limiting the negative effects after occurrence of expected gas breakthrough. Due to small clearances involved, the ICD deployment presented a significant operational challenge. Despite the higher initial completion costs associated with ICDs, they can provide a cost-effective way to reduce long-term operating costs and increase yield. Production targets are achieved with longer, but fewer wells, maintenance and overhead. From a reservoir management point of view, ICDs can improve the productivity index (PI) by maximizing reservoir contact, minimizing gas coning by operating at lower drawdown, and increasing overall efficiency .Swelling-packers were used to compartmentalize the horizontal and build sections, allowing better drawdown control and eliminating cross-flow issues. The completion required re-thinking of the established acid-wash treatment procedures, ultimately improving the overall well clean-up. Integrated analysis methods using steady-state wellbore hydraulic and 3D dynamic simulators were performed to generate flow profiles and calculate ICD pressure drop along the horizontal section. The models were updated using results from logging-while-drilling (LWD) and with real-time modifications to the initial design.
To verify the inflow profile along the length of the ICD completion, production logging (PLT) was conducted. The inflow profiles compared favorably with those predicted by the models.
Tellefsen, Kristoffer (Norwegian University of Science and Technology) | Ding, Songxiong (Telemark Technological R & D Centre) | Saasen, Arild (Det Norske Oljeselskap ASA) | Amundsen, Per Amund (U. of Stavanger) | Fjogstad, Arild (Baker Hughes Inc.) | Torkildsen, Torgeir (Wellpos AS)
The magnetic property of the drilling fluid is one of the substantial error sources for the determination of azimuth while drilling deviated wells. These errors may be in the range of 1-200m if drilling long, deviated intermediate sections. Therefore, these effects represent a significant cost to be mitigated. The error becomes even more pronounced if drilling occurs in arctic regions close to the magnetic North pole. Added clays, weight materials and the tubular wear are anticipated to distort the geomagnetic field at the location of the magnetometers. The effect on the magnetometer readings is obviously linked to the amount of magnetic material in the drilling fluid. The problem has been studied both by laboratory experiments and analyses of downhole survey data. However, there are several inconsistencies in the results, and the phenomenon is not fully understood.
In the following it is shown how the magnetic distortion relates to some drilling fluid additives. A series of experiments have been conducted to increase the understanding of the effects. First, a series of experiments showed that presence of free iron ions do not contribute to magnetic distortion. Next, a series of experiments with bentonite-based fluids were conducted, showing the effect of bentonite on magnetic shielding. Measurements on a series of clean, laboratory made oil-based drilling fluids showed that the magnetic shielding did not increase by the addition of organophilic hectorite clays. Finally, eroded steel from an offshore drilling location was added into the oil-based drilling fluid. These swarf and steel fines significantly increased the magnetic shielding of the drilling fluid. This paper also outlines how much the drilling direction may be distorted by the presence of these additives and contaminants.
Reaming while drilling can be a more economical drilling technique than conventional drilling. Downhole failures can occur for a variety of reasons, and failure as a result of excess dynamic loading on the bottom hole assembly (BHA) components may be the most mysterious. One of those mysteries is the static and dynamic distribution of axial load between the bit and the reamer. This paper presents an approach using the explicit finite element method to model the static and dynamic interactions between the bit, the reamer and the formation of the BHA.
The results for axial displacement from the explicit finite element method are compared to theoretical results for a self-weighted column. Also, the axial vibrations are compared to the theoretical natural frequencies. Once the comparison showed the explicit FE method gives the same theoretical results, the model is expanded to better reflect actual downhole conditions. The model includes a bit and a reamer from which the interaction can be studied with an emphasis on axial loading. A weight dependent velocity boundary condition is used to model formation penetration of the bit and reamer. This models the relationship between the axial load on the reamer and the bit. This so-called drill-ahead model can be used to better understand the dynamics of the BHA.
Results from this study show the amplitude of the axial oscillating force on the reamer was greater than that of the force on the bit. Drilling with a more aggressive reamer will decrease the side forces on these components for the case studied. In addition, for a change of load at the top of the model, the reamer can take more of the transient load than the bit.
Welch, John Charles (Baker Hughes Inc.) | Newman, Caleb Ray (U. of Houston) | Gerrard, David Peter (Baker Hughes Inc.) | Mazyar, Oleg A. (Baker Hughes Inc.) | Mathur, Vipul (Baker Hughes Inc.) | Thieu, Vu (Baker Hughes Inc.)
The oil and gas industry is continuously looking for material and tool designs with more robustness that provides greater operational flexibility in aggressive environments. New elastomeric systems that have been enhanced at the nanometer scale have been engineered to address these needs.
Nano-enhanced EPDM showed 95-percent lower swelling rate in oil at ambient temperature. Nano-enhanced HNBR compound exhibited 15 times lower absorption in 300°F hydrocarbon fluid. Nano-enhanced FEPM compound showed 20 times lower absorption. Nano-enhanced FEPM bladder material submersed in oil at 300°F yielded a three-fold reduction in the gas transmission rate of a hydrocarbon blend containing both CO2 and of H2S. The same nano-enhanced material showed a 50-percent reduction in the degradation effects of H2S on the NBR physical properties. All of the above are lab results, and the comparisons were made to baseline commercially available rubber compounds without nano-enhancement.
Our results demonstrated that nanotechnology can be very effectively used to significantly modify properties of commonly used rubber compounds in the oil and gas industry. The oil swelling rate can be drastically reduced to give operators a greater flexibility in setting the packers and reducing intervention. Sour gas-based slowdown of material retardation translates to higher tool life. These findings can be used to design new packers, sealing elements and other elastomeric components used in downhole environment. This paper will present our recent lab results along with postulated mechanism on how nanotechnologies can impact material performance in downhole applications.
Thin films, typically < 1µm thick, are created by alternately exposing a substrate to positively-charged and negatively-charged molecules or particles, as shown in Figure 1. In this case, steps 1-4 are continuously repeated until the desired number of "bilayers?? (or cationic-anionic pairs) is achieved. Each individual layer may be 1-100+ nm thick depending on chemical properties, molecular weight, charge density, temperature, deposition time, counterion, and pH of species being deposited. The ability to control coating thickness down to the nanometer level, to easily insert variable thin layers without altering the process, economically use raw materials (due to thin nature), self-heal and process under ambient conditions are some of the key advantages of this deposition technique. These films often have properties that are better than comparable thick films (>>1µm).
2.1 Polymer Coating System
The main coating of interest is the all-polymer system containing branched polyethyleneimine (BPEI) and poly(acrylic acid) (PAA), with the final crosslinking by glutaraldehyde (GA). Details of each solution are shown below:
Annular flow of non-Newtonian fluids remains a ubiquitous phenomenon in drilling operations but accurately estimating the frictional pressure loss with drill pipe rotation still poses a great challenge. Since annular frictional pressure losses increases the equivalent circulating density (ECD), it becomes imperative to accurately estimate the annular pressure loss in order to keep the ECD above the pore pressure and below the fracture gradient especially in deep offshore drilling where the pore pressure and fracture pressure are so close together.
When annular flows are encountered, a common practice is to calculate an effective diameter such that the flow behavior in a circular pipe would be roughly equivalent to the flow behavior in the annulus. This equivalent diameter definition replaces the diameter term in the friction factor, effective Reynolds number and Taylors number equations used for pipe flow thus resulting in different frictional pressure loss estimation. As a result, the selection of appropriate correlation for the respective fluids, flow regimes and putting into consideration pipe rotation has become important but has received very little attention.
In this study, the seven different equivalent diameter definitions used for estimating frictional pressure losses in an annulus were reviewed and theoretical analysis were performed on experimental data obtained from literatures to determine the effect of these definitions on wellbore hydraulics. Pressure loss ratios (PLR) which relates pressure loss with pipe rotation to pressure loss without pipe rotation weredevelopedfor each equivalent diameter definitionusing dimensional analysis techniques. These hydraulic models combined with conventional frictional pressure loss estimation were tested with experimental measurements to determine the model with an equivalent diameter definition that best predicts frictional pressure losses for power law fluids.
Deepwater developments are very high cost ventures in complex reservoir environments. Acquiring insight into the reservoir inflow distribution and location of water inflow using conventional technology, such as production logging tools, is very problematic in the deepwater environment where wireline intervention into live wells is a major risk and cost.
Intelligent chemical tracers are an emerging technology that provides insight into the inflow distribution without intervention operations or major alterations to the completion design. The tracers consist of unique chemical compounds that are combined with unique polymer formulations into a matrix that resembles strips of plastic. The matrix is designed to release the tracer when contacted by the target fluid, either oil or water.
The matrix strips are deployed with the initial completion installation at strategic locations in the completion so that fluids entering the completion contact the matrix. At the surface, samples of the produced fluid are acquired and analyzed for the presence and concentration of each unique tracer that has been deployed in the completion. The concentration data is plotted vs time or produced volume. Analysis of these plots can yield answers to very valuable reservoir management
questions such as:
- Are all the intervals producing?
- What is the relative contribution of each interval?
- Where is water break-thru occurring?
Deepwater completions are frequently completed with sand screens. The typical sand screen design contains spaces where the tracer can be integrated without any changes to the design. If the screen design is not readily compatible with the matrix strips, specially design tracer carrier mandrels can be added to the completion.
The passive nature and very low risk of deploying this technology is very attractive in deepwater wells.
This paper reviews the fundamentals of intelligent tracer technology, methods of integration into deepwater completions and some field examples previous deployments.
The Hadrian-5 prospect in the United States (US) Gulf of Mexico's Keathley Canyon 919 block was drilled by the operator in ~7000-ft water depth as one of the first Gulf of Mexico wells drilled after the deepwater moratorium. This exploration well was permitted under the new regulatory requirements of the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). These new requirements included additional blowout preventer (BOP) certification and testing, incorporation of selected API recommended practices, and certification of the well design by a registered professional engineer.
In addition to the well design regulations, BOEMRE required operators to calculate a worst-case discharge scenario and develop plans to contain that scenario. Well containment plans were developed that included the newly-formed Marine Well Containment Company's (MWCC) response capabilities.
The well was drilled between March and August of 2011 to a total depth (TD) of 19,631 ft and encountered several hydrocarbon intervals that were safely managed. The rig selected for this well was the dynamically-positioned (DP), Maersk Developer semisubmersible.
This paper describes the planning, permitting, and execution of this challenging well. Topics covered include:
• New permitting requirements for federal waters in the US
• Worst-case discharge scenario and impact on casing design
• Elimination of trapped annular pressure via well design
• Minimizing vibrations in the tuff formation of the Hadrian mini-basin
• Managing the uncertainties associated with sub-salt formation pore pressures
• Drilling and casing mobile tar zones
The well was drilled and evaluated in a safe manner with no significant incidents even though the geologic formations encountered were different than predicted.
Cockram, Mark Andrew (BG Group plc) | Ritchie, Allan Fraser (Schlumberger) | O'Keefe, John (Smith Bits, a Schlumberger Company) | van der Laan, Rene (Smith Bits, a Schlumberger Company) | Sundfoer, Erik (Smith Technologies) | Larsen, Olav (Schlumberger) | Kleimeer, Peter (M-I Swaco) | Rapp, Tom (The University of Aberdeen) | Shotton, Peter (Smith Services, A Schlumberger Company) | Gjertsen, Ole Jacob
To efficiently develop reserves in the Norwegian North Sea, the operator must drill a challenging 12¼?? directional borehole through a Chalk formation with high stick-slip potential. In Gaupe North, a negative vertical section was required in the initial kickoff to properly line up the well path before entering the reservoir target. The reservoir is comprised of channel/sheet sandstones interbedded with shale sequences with different pressure regimes and nearby reservoir depletion issues. The 8½?? wellbore must penetrate an unstable organic shale just above the reservoir, infamous for causing hole stability problems and stuck pipe events. The regulatory agency requires this shale to be drilled in an 8½?? section, requiring long exposure time, which increases risk for hole problems when running the production liner. The objective was to efficiently drill these trouble-zones and deliver two horizontal producers in a cost effective manner using an integrated engineering solution.
To achieve the objective, a sophisticated multidisciplinary approach was employed including: bit/BHA offset analysis to reduce stick-slip in the chalk; BHA/RSS and drilling fluids modeling/planning; and drilling parameter plots to identify optimum RPM/WOB. Also, a real-time parameter analysis system was deployed to optimize ROP without compromising hole cleaning or well integrity.
The synergy provided by a fully integrated service provider increased drilling performance and was a major contributor to the success of the Gaupe wells performance. Well 6/3-A-1H broke the previous Rushmore index for subsea development wells in the region and set a Norwegian record for wells in this class. Both wells (15/12-E-1H & 6/3-A-1H) achieved positive P10 curves and saved a total of 18 days vs AFE. Compared to an analogous UK North Sea field, significant increases in ROP were achieved resulting in the wells being drilled 20+ days faster than benchmark. The average increases in ROP for the two Gaupe wells were approximately 146%, 47% and 148% in the 17½??, 12¼?? and 8½?? sections respectively.
Geomechanics and hydraulics modeling are commonly used to optimize drilling performance and to reduce non-productive time (NPT). The geomechanics model indicates safe mud weight parameters, optimum casing points, and wellbore stability analyses. The hydraulics model simulates the wellbore and drilling fluid parameters to optimize the flow rate and rate of penetration (ROP) within equivalent circulating density (ECD) constraints. Real-time drilling data are used to update the models: the pore-pressure/shear-failure gradient and fracture gradient boundaries for geomechanics; and ECD, circulating system pressure drops, and annular cuttings load parameters for hydraulics. Each real-time model strives to ensure that operations are optimal, safe, and cost effective, as well as to provide updated models for future planning purposes.
This paper focuses on collaboration between geomechanics and hydraulics analysts in the planning, drilling, and post-drilling phases of the well. A geomechanics model determines the safe mud weight operating window and casing points, whereas the hydraulics model simulates ECD for defined mud properties, drilling parameters, and wellbore geometry. A synthesis of the two models enables the previously mentioned information to be compared and merged before spudding the well. Real-time collaboration between models enables each model to be updated with pertinent information from the other, ensuring that drilling operations are performed within optimum mud weight and ECD constraints. The geomechanics model can use real-time ECD data from the hydraulics model when a pressure-while-drilling (PWD) tool is not being used. In turn, the hydraulics model requires updating when the safe mud weight limits are being exceeded. The two models can each use information from the other when performing the post-well analysis and planning for the next well. Both models are valuable tools when used individually, but they become powerful, superior companions when used in conjunction with one another.
Emerging ultra high-pressure/high-temperature applications in downhole service have created the need for the development of new sealing materials. To address this emerging need, a series of modified polymeric materials were developed. The new material displayed strong mechanical properties below glass transition temperature (Tg). Above Tg, the material displayed stable elastomeric properties up to 400° C. The thermal rating of the material is beyond the available commercial thermoplastics and elastomeric materials. Furthermore, the Tg of the material can be adjusted from 97° C to 215° C. The material was aged in a crude oil at high temperature. Dynamic Mechanical Analysis (DMA) measurements were performed on the material before and after aging. The material displayed excellent resistance to the crude oil. In addition, API extrusion-resistance measurements were performed on the new material at various temperatures and various pressures. The extrusion resistance of the new material was superior to the available commercial elastomeric materials, including perfluoroelastomers. Thus, the material has great potential for use in emerging high-temperature sealing applications and other oil and gas applications. This paper describes the work involved in conducting this development work and test results.