Areepetta Mannil, A. (Schlumberger) | Lobov, M. A. (Schlumberger) | Buyanov, M. (Schlumberger) | Chang, K. (Schlumberger) | Silva, L. (Schlumberger) | Kazakov, A. (Lukoil-Nizhnevolzhskneft) | Eliseev, D. (Lukoil-Nizhnevolzhskneft) | Zemchikhin, A. (Lukoil-Nizhnevolzhskneft)
Korchagina and Filanovskoe oil fields in the north Caspian Sea have many extended- and mega-reach wells that uses inflow control device (ICD) screen completions with sliding sleeves. This completion technique empowers the operator with the ability to shut off unwanted water/gas breakthrough and allows for more control of injection or inflow with unlimited number of stages or zones. This paper describes a new verified workflow to successfully intervene these wells and manipulate (open/close) these sliding sleeves using coiled tubing (CT).
It has proven challenging to shift these sliding sleeves using conventional methods with CT owing to the limitation of available weight on bit (WOB) at the toe end of those extended-reach wells, even when using large-size CT strings. The new proposed workflow uses a well tractor operated in tandem with a hydraulic shifting tool to generate the required shifting force downhole. The bottomhole assembly (BHA) also includes a novel flow control sub, assembled between the shifting tool and the tractor, with the ability to control the flow to selectively activate the tractor, the shifting tool, or both, based on surface commands by manipulating pump rate.
To verify the methodology, a realistic well scenario was simulated at a test site by installing two ICD screens with sliding sleeves at the end of a 1,000-ft-long horizontal flow loop. The sleeves on each ICD screen required approximately 4,000 lbf set-down force to open. The available WOB at the end of horizontal loop with 2-in. CT was only 1,000 lbf; applying more than 1,000 lbf set-down load could have detrimental effects, including CT buckling. The 3⅞-in. OD well tractor used for the job was able to generate 6,000 lbf of pulling force downhole, which was more than enough to shift the sleeves open. Both sleeves were successfully opened by tractoring down while maintaining both the tractor and the shifting tool in the on position, which was achieved by manipulating the flow control sub using pump rate cycles. Both sleeves were then successfully closed, one after the other, by pulling with the CT with the tractor turned off while maintaining the shifting tool in the on position, again achieved by manipulating the flow control sub. Live downhole pressure and force measurements were key in confirming proper functionality of the tractor and identifying different tool modes. Having real-time data is also crucial for proper depth correlation using casing collar locators (CCL) or gamma ray measurements to ensure activating the correct sleeves.
This marks the first time that a workflow was verified on the use of pull force generated by a well tractor to manipulate completion accessories in extended-reach well interventions using CT. The technology, preparation, results, and prospects of implementation are discussed in this paper.
Coiled tubing (CT) is widely used during sand cleanout applications for its multiple benefits, such as speed, cost effectiveness, minimum reaction time, efficient operations, the ability to perform live intervention cleanouts, etc. However, these benefits are difficult to achieve in complex, offshore, high-pressure/high-temperature (HP/HT), or big bore wells because of various operational constraints, such as weight, dimensions, wellbore trajectory, and completion design, resulting in increased expenditures and operation time for workover activities.
This paper describes how these constraints were eliminated using a synergy of an innovative fluid system and engineering to perform a challenging, balanced sand cleanout treatment using 1.75-in. 5800 m long CT in ~500 m of a 7-in. 35-lbf casing section executed in a 5300-m deep HP/HT well.
The deep HP/HT well had a minimum restriction of 2.56-in. in the upper completion limits, requiring large-diameter CT strings and a bottomhole assembly (BHA). Feasibility studies for use of a 1.75-in. CT vs. 2-in. CT string were performed, resulting in the selection of the 1.75-in. string. Another challenge was executing sand cleanout in a balanced condition, resulting in the selection of a saturated 13.1-lbm/gal potassium-formate (K-formate) brine. The combination of all three major constraints, a) 500-m long 7-in. section, b) use of 1.75-in. CT string, and c) use of saturated brine, made the cleanout design challenging, as sand cleanout with CT requires circulation rates, net particle rise velocity, friction pressures, viscosity, and fluid properties within the design envelope. However, the inversely proportional nature of such treatments means tuning of one property would decrease the operational feasibility of other properties.
Based on results of several tests, a customized fluid recipe was designed containing a gelling agent that can become hydrated in saturated brine and remain stable at high temperatures. A compatible friction reducing agent was used to help reduce pumping friction to attain the desired annular fluid rate and velocity. A field test was performed with the designed fluid at surface with a CT string that was to be used for operations, confirming the effectiveness of the fluid recipe.
Using downhole turbulence created by the tool, along with the custom-designed recipe in combination with wiper trips, the necessary design parameters were achieved for the cleanout operation, resulting in a) effective sand cleanout with ~98% efficiency, b) reduced operating hours, c) cost savings on workover operations, d) safer operation by keeping the well in a balanced condition, and e) a contingency action in place for screenout during fracturing treatments.
The procedure described in this paper, along with lesson learned, can be applied in similar applications to help optimize results and overcome related challenges.
Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions.
Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively.
The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine.
The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (
In deepwater Gulf of Mexico, cement placement through coiled tubing (CT) has been proven over several decades to be a valuable, versatile, and cost-effective tool for the through-tubing plug and abandonment of depleted oil and gas producers. In this paper, several present-day recommendations and best practices in relation to CT cementing for well abandonment are described.
CT cementing is typically used for well abandonment when leaving part of the production tubing in place is deemed beneficial from an economic or operational risk standpoint. As demand for the reliable placement of permanent cement barriers during well abandonment continues to grow, the importance of optimal design methodology, laboratory practices, and placement techniques associated with CT cementing has also increased. For instance, one of the most important aspects is to design a thin yet stable cement slurry. In addition, thickening time tests must account for the time a slurry is in the CT reel at surface before travelling downhole. Fluid placement techniques should account for the use of any downhole tools and be adjusted accordingly.
In recent well abandonments, a high success rate in the placement of cement plugs through CT has been observed. The main contributor to this success is the consistent manner in which the best practices described in this paper were followed. These methodologies also include some that have slowly evolved over time. For example, during well abandonment, one procedure that appears to be gaining popularity in some situations is the running of inflatable cement retainers with the ball on seat. In regards to CT cementing, this has often resulted in modified strategies, with fluid placement techniques counteracting the inability to pump any fluids through the CT prior to setting the retainer.
This paper is based on several recent abandonment campaigns using an intervention vessel in the Gulf of Mexico in 2016. Throughout the course of these particular campaigns, a total of 32 cement plugs were placed through CT, all of which were successfully verified, thus avoiding costly remedial placement. Although different conditions and well-specific challenges can slightly alter the approach taken, there are several steadfast techniques that appear to be effective in the consistent delivery of desired results.
With growing regulatory requirements focusing on well safety and risk mitigating barriers, there is an increased requirement for surface-controlled subsurface safety valves (SCSSVs). Most SCSSV's provide well protection by means of a normally closed flapper-type closure mechanism that prohibits deployment of capillary or through-tubing based solutions which would not allow the flapper to fully close in the event of an ESD.
Operators desire cost effective rig-less deployment of capillary-based solution(s) to increase production and or reconnect a non-functional hydraulic control system. To date flow actuated subsurface controlled safety valves have provided a solution for loss of hydraulic control of a tubing-mounted SCSS; however, these valves are becoming less desired due to decreasing acceptance from regulatory agencies. Additionally, traditional post-completion chemical injection systems beyond a SCSSV have not been possible for continuous well-stimulant injection, nor has a solution for post-completion gage monitoring past a SCSSV been achieved.
This paper discusses technology enabling rig-less ability to reconnect a hydraulic system to a SCSSV or Safety Valve Landing Nipple by deploying a thru-tubing capillary based system inside the SCSSV / SVLN while maintaining functionality of the safety valve. In addition this solution can be utilized for continual injection of chemicals directly below the SCSSV and onwards to production zone depths. Further a downhole gage can be installed directly below the SCSSV and up to depths of 20,000 feet. Each of these functional characteristics can only be realized though the introduction of this novel capillary based solution, which maintains the "fail-safe" closure capability ensuring well control against a catastrophic event were to occurring at the surface or below.
Heavy oil fields can be developed using diluent (light oil, condensate, etc.) injection at the well level as a flow improver. However, diluent can also be injected at the surface, as used in Canadian heavy oil production. Benefits of topside diluent injection include among others (1) improved oil/water separation in the surface processing facility, (2) improved viscosity, and (3) better final crude quality. Such blending activities are often associated with additional OPEX due to the high price of diluent, which can add significant costs to a development. This paper describes an Integrated Asset Modelling (IAM) solution designed to minimize the topside diluent requirement while honouring technical and market crude specifications. The case studied is an offshore heavy oil field consistings of two reservoirs with API gravities of 14 and 12, and oil viscosities at reservoir conditions of 70 cp and 500 cp.
The production facilities include a two-stage surface processing facility followed by a coalescer aimed to separate the water from the crude. Diluent is injected in the surface processing facility prior to the second stage separator. Operating variables include (1) the topside diluent injection rate and (2) the temperature of the second stage separator. The difficulty of the production optimization problem lies in the non-linearity of the process and viscosity models, and the consistency of the fluid’s PVT description throughout the production system.
The proposed optimization solution is coupled with a reservoir simulator to determine optimal topside diluent requirements over time and foresee eventual bottlenecks in the surface infrastructure design. The proposed solution can also be used as a real-time management tool during the production phase to find the optimal operating point based on real-time data. The optimal operating point ensures the lowest diluent consumption while meeting all system constraints, providing the framework for significant cost savings.
A newly-developed 3 ½-in. coiled tubing telemetry (CTT) system has been used for the real-time operational optimization of such coiled tubing (CT) applications as milling, cleanout, logging, and perforation, in an offshore multi-well campaign in Norway.
The CTT system consists of surface hardware and software, a dual-purpose wire inside the carrying CT, and the multi-function bottom hole assembly (BHA). The wire transmits electrical power from surface to the downhole sensors located in the BHA and the downhole data from these sensors to surface. The BHA, designed in one of three sizes (i.e., 2 ⅛-, 2 ⅞-, and 3 ½-in.), contains a casing collar locator (CCL) and two pressure and temperature transducers that are capable to measure downhole data inside and outside the BHA. One of the main advantages of the CTT system is its versatility. For instance, switching between applications is as simple as only changing a certain part of the BHA. This reduces the need to rig-up and rig-down and leads to operational time and cost savings to operators. Another main advantage stems from its real-time downhole data certainty, as the CT field crew can immediately make decisions based on dynamic downhole events.
A few papers have been published recently regarding a similar 2 ⅛ and 2 ⅞-in. CTT systems (SPE-174850, IPTC-18294, SPE-179101, and SPE-183026). In this paper, several case studies are presented for the 3 ½-in. CTT system for the first time. For instance, in the first well, the CTT system helped remove approximately 26,500 lb of scale through a complex wiper trip schedule, effectively preparing the well for re-completion by the main rig. In the second well, the CTT system helped pull all shallow and deep plugs and perforate three intervals in one run. In the third well, the CTT system helped clean out the well, set a plug, and re-perforate it. In addition to successfully performing all these operations, several other benefits resulted due to the real-time downhole data monitoring provided by the CTT system. For instance, the fluid friction reducer (used for reducing the fluid frictional pressure drop) was effectively used at volumes of 70-75% lower than those recommended when the CTT system is not used. Also, all these operations were performed without the need to mobilize most of the wireline and tractor equipment and crew, saving an estimated time per well of six days of wireline logistics and work.
The paper briefly describes the 3 ½-in. CTT system and discusses the data acquired during these field operations. The system performance and operational benefits confirmed are presented. These findings outline the versatility of the 3 ½-in. CTT system, the predictability of successful operations resulting from using this system, and the cost and time savings to operators.
ABSTRACT: Based on the theory of the limit equilibrium method of slope stability analysis, this article studied the infinite slicing calculate theory under the circumstance that the loess slope sliding-plane does not cross the slope foot. Through the formula derivation, the analytic formula of the sliding torque Mr, and resisting moment Mf were calculated, and then it was concluded that the safety factor K is function of the smooth arc radius R, the sliding body string angle a and angle of slope plane distance Δl. We simplified the process of searching the most dangerous sliding surface on genetic evolution method reasonably and effectively. On the basis of concept of replication, hybridization, variation, competition and selection in biological genetic evolution steps, in the process of the most dangerous sliding surface search, change the two-way variation for one-way and increase mutant genes of the slope angle of plane distance. While other factors remain unchanged and only one of the factors changes, the minimum safety factor was computed under the restrictive condition and its applicability was determined. After changing another factor and repeating the searching process, the minimum safety factor and the corresponding value of various factors were figured out finally. Realizing search on the most dangerous sliding-plane does not cross slope foot. Also, we used FORTRAN software program to complete the compilation of the search procedures. The engineering examples have confirmed that this method is feasible and safe. This paper has important value of reference to improve the loess slope stability analysis theory.
At present, the theory of the limit equilibrium method is the main approach to analyse slope stability. However, it simplifies the boundary conditions of the landslide.
Different assumptions lead to various theory of limit equilibrium method of slope stability analysis.
The common theories are Bishop, Janbu, Spencer, Morgenstern-Prince and so on.
For various limit equilibrium methods stand for different hypothesis, they make remarkable effect on results and precision.
At the same time, these methods have complete and meticulous theoretical derivation. Because the methods themselves make some simplifying assumptions. Thus some unavoidable limitations and the final results are often different from the engineering practice, which may leads to low precision of results because we can only rely on the experience of slopes. In view of that, particularly on loess areas, it's eager to make an intensive study of each past theory to draw more precise limit equilibrium methods of slope stability analysis to guide the project. Moreover, it could reduce disasters of engineering to secure the safety of people's life and wealth.
Currently, well control events are almost exclusively detected by using surface measurements. Especially in deepwater, where the riser comprises a substantial section of the wellbore, early kick detection is paramount for limiting the severity of a wellbore influx and improves the ability to regain well control.
While downhole data is presently available from downhole tools nearby the bit, available data rates are sparse as wireless telemetry bandwidth is limited and wellbore measurements compete with transmission of other subsurface data. High-bandwidth downhole data transmission system, via a wired or networked drillstring system, has the unique capability to acquire real-time pressure measurement at a number of locations along the drillstring.
The paper describes the four processes to improve well control for deepwater operations through the use of downhole data independent from surface measurements. First, networked drillstring provide efficient kick detection and the identification of ballooning zones. Gas inside the riser is also detected and decision support is offered between using the mud-gas separator or diverter. Second, a methodology is proposed using direct measurement of downhole real-time pressure for maintaining constant bottomhole pressure during well kills in deepwater. Third, downhole surge and swab pressures are available through measurement while tripping system. Fourth, well control barriers are verified using downhole information, independently from surface data. All of these workflows allow for higher levels of automation, supporting wellsite personnel and improving the safety of operations. The paper presents examples of field data that illustrate these cases.
The process of mining causes changes in the seismic velocity of the rocks in the vicinity of the openings. Two effects are present: First, increased stress in the rockmass results in an increase in seismic velocity. Second, regions where the rock is highly fractured show lower seismic velocity and higher attenuation. Mapping the seismic velocity distribution and changes in velocity caused by mining could have two immediate benefits: mining-induced seismic events could be more accurately located, allowing their use in assessment of rockburst hazard; and the zones of high stress and fracture could potentially be directly imaged. A geophone array installed on the surface above a longwall coal mine was used to record seismic signals from the shearer as it cut coal. Major differences in velocity were seen for regions in front of the mining face compared to the highly fractured and caved zones behind the face. In order to test the viability of imaging this caved zone behind the face, a sledgehammer source was used in an underground roadway to augment the data from the shearer, and refracted arrivals were generated using surface sources. Images produced from this data repeatedly show, not only a low-velocity caved zone behind the face, but also a high-velocity region in front of the face which could be caused by increased stress in this region. The conclusion is that seismic changes caused by mining are large enough to be detected and imaged.