Excessive water production from unwanted zones in oil producing wells is one of the major challenges faced by the oil industry. The applicability of organically crosslinked polymer (OCP) systems as sealants for water shutoff treatments in temperatures up to 350°F is well documented. However, their effectiveness at temperatures above 350°F has not been evaluated. This paper presents experimental data from using an OCP system for water shutoff treatments at 400°F.
At temperatures around 400°F, crosslinking is expected to happen faster and can lead to premature gelation of the recipe before the entire treatment is in place. Thus, controlling the gelation time at such temperatures is extremely crucial. Optimizing the amount of retarder is essential to provide adequate time for placement of the treatment fluid. This paper provides gelation time data at temperatures between 350 and 400°F with different amounts of retarder. With an optimum amount of retarder, the OCP showed a gelation time of 1 hr 20 min.
This paper also describes the experimental setup used to study and determine the long-term stability of the OCP system at 400°F. Sand packs measuring 1-ft long were used for the test to simulate formation conditions. Once the optimized OCP recipe was gelled inside the sand pack, measurements were taken by gradually applying incremental differential pressure (?P) to evaluate the sealant at temperature, as well as the threshold ?P the system could withstand. Even after one month at 400°F, the OCP recipe was able to sustain a ?P of 950 psi over the sand pack.
The data indicates the applicability of this system as an effective conformance product to shut off water-producing zones over an extended period of time at 400°F.
In recent times the topic of well barrier integrity has become increasingly salient. Within the well completion arena, there have traditionally been two main alternatives for barrier plugs used for packer setting or temporary well abandonment; these are the metallic flapper or ball type isolation plugs. This paper describes the evolution of an innovative glass type barrier plug from its first appearance in the oilfield in 2004, to the deployment of third generation prototype systems into wells in the North Sea today.
Traditional ball or flapper type plug systems need to operate in two states: open and closed. This functionality typically necessitates the use of dynamic seals, which also have to compensate for the pressure differential applied across the plug. Plugs built in this manner can be prone to malfunctions in the dynamic seals and have limitations as to the pressure differentials that can be applied to them when opening. Additionally as the balls or flappers themselves are traditionally manufactured using metallic alloys, in the event that a plug fails to open the only alternative is milling, which if successful, will still leave a restriction in the well limiting options for future well interventions.
Glass barrier plugs have to operate in two slightly different states, solid or shattered. When the plug is run in hole the glass is in a solid state with pressure integrity maintained using static elastomeric seals. Once well operations have progressed to the stage when the plug needs to be opened, a preinstalled trip saver can be activated which would shatter the glass and open well communication. Operating in this manner avoids the use of dynamic seals thereby increasing plug reliability. Other major advantages are that the differential pressure applied across the plug when opening has no effect on the plugs functionality and since the plug is made out of glass, in the event of a trip saver malfunction the plug can be opened using a shoot down tool, a spear, or milled within approximately 10 minutes using a wireline tractor (Welltec, 2011) leaving a full bore ID for future well interventions.
This paper describes how BP Norway and TCO used the lessons learned from two generations of Glass Barrier Plugs (GBPs) to develop a system with increased debris tolerance, improved redundancy and a larger inner diameter.
Ussenbayeva, Khadisha Yerikovna (Tengizchevroil) | Utebaeva, Dinara (Tengizchevroil) | Molesworth, Gregg R. (Chevron USA Inc.) | Dunger, Darrin (Tengizchevroil) | Akwukwaegbu, Chinedu Franklyn (Chevron Corp.) | Salikhov, Timur M. (Tengizchevroil) | Kamispayev, Akylbek (Tengizchevroil) | Zielinski, Matthew Bernard (Chevron Corporation) | Yakovlev, Timofey (Schlumberger) | Savin, Artemiy | Aglyamov, Mansur
Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities.
A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity.
The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers.
Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design.
The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.
As the oilfield industry requires new techniques to generate diversion over large pay zones and easier methods to perform workover operations and perform interventions through Coiled Tubing, research is focused to provide the industry with new technologies that support the growing demand for oil and gas in the world.
Fluid systems that are used to divert acid over large zones and generate non-mechanical isolation on a wellbore have traditionally been viscosified fluids and solid particulates. These substances create (in most cases) a drastic permeability reduction in the near wellbore area of producing zones that are meant to be protected. In operations that require divertion or the generation of a temporary plug, researchers have found that polymer based fluids are best suited, since they create less damage on the formation, and in the case of temporary plugs they can withstand higher differential pressures. The use of such fluids has reduced considerably the need for more complicated deployed techniques, such as mechanical packers, bridge plugs and mechanical diversion techniques.
This paper describes the first application of a polymer gel system in Saudi Arabian gas fields to isolate a section of a payzone on a vertical well, the system's design and operational challenges, and finally, its successful outcome and results. The objective of this application was to place a temporary plug between two producing zones to be able to selectively stimulate the lower zone.
Accessibility to wells location requiring work over is so important to ensure safe production, work environment and provides a protection to the existing assets including wells, pipelines and other production facilities. The locations of multiple wells are designed and constructed to provide enough space between wells for a rig to drill them safely and smoothly. Besides, they should accommodate future work over operations. When location has several wells with limited space in between, it is challenging to work over them with full compliance to the safety guidelines. Saudi Aramco work over team has managed successfully to work over wells in very congested location in one of north onshore fields where the spacing does not exceed a few feet. In this paper, a light will be cast on the work over campaign launched recently to work over these wells to convert them from purely vertical wells into horizontal to bring birth to them after being dead for high water production. The challenges including accessibility to well sites, site preparation, securing wells nearby, protection of environment and safe operation are all going to be addressed and discussed in details. Also, measures taken to overcome difficulties encountered especially safe rig up are presented and explained as well.
Jackson, Alfred M. (Zakum Development Co.) | Al Azizi, Badr (ADMA-OPCO) | Kofoed, Curtis Willard (Zakum Development Co.) | Shuchart, Chris E. (ExxonMobil Upstream Research Co.) | Keller, Stuart Ronald (ExxonMobil Upstream Research Co.) | Sau, Rajes (ExxonMobil Upstream Research Co.) | Grubert, Marcel Andre (ExxonMobil Upstream Research Co.) | Phi, Mike Van (Exxon Mobil Corporation)
In this paper, a new carbonate stimulation methodology and its impact to the planning of very long, open hole completions will be presented. While the key objective of stimulation is to connect the well to the reservoir, completion equipment design and related well performance have become more important factors. Traditional methods of stimulation modeling and fluid placement are no longer sufficient for these types of wells.
This paper introduces how completion design becomes more complex for more aggressive stimulations. For example, completions with pre-drilled or slotted liners for stimulation with coil tubing acid wash are less sophisticated than ball drop liners for high-volume acidizing or fracturing. In long horizontal completions, computer modeling of stimulation needs to address the flow conditions caused by liners, swell packers and inflow control devices (ICDs). Recent well planning for a long horizontal pilot well (Pilot Well 5) has included the use of new carbonate matrix stimulation software to design a fit-for-purpose completion liner that will accommodate bullhead treatment of a long completion interval. Various completion designs were considered based on objectives from reservoir engineering and geology. Being part of a pilot well program, the strategy is to test fit-for-purpose liners that would balance completion cost with long term productivity and recovery.
The well design required more than 100 runs of the new carbonate matrix acidization software to finalize a liner design that employs over 200 holes distributed along the length of the lateral. The final design was developed to accommodate uncertainties in the reservoir properties and allow for safe and reliable rig operations. The resulting design could serve as a lower-cost alternative to ball drop stimulation liners for long openhole completions.
Al Braiki, Saleh (ZADCO Petroleum Co) | Al-Sawadi, Obadah Saleem (Zakum Development Co.) | Afzal, Muhammad (Zakum Development Co.) | Odeh, Nadir M.M. (ZADCO Petroleum Co) | Yar Khan, Naeem Shahid (Zakum Development Co.) | Al Hosani, Abdulla Hasan (ZADCO Petroleum Co) | Bani Malek, Ahmed (ZADCO) | Yousef, Anwar (Halliburton Co.) | Faruqi, Shamim (Halliburton)
In ZADCO's giant offshore oilfield, the Surface-Controlled Downhole Safety Valve (SC-DHSV) system of some oil producers failed to operate. Thorough investigation revealed that SC-DHSV landing nipple sealbore damage was the root cause of failure. The failed SC-DHSVs were temporarily replaced with A-3 Storm Choke Valves.
The conventional solution to restore the integrity of a failed SC-DHSV was the workover. However, efforts were made in identifying a viable rigless solution by thoroughly reviewing the available options and as an alternative, special oversized B-Type seals were chosen to substitute the existing conventional V-Type packings that failed to seal in said valves.
To ensure safe field implementation, a risk assessment was conducted followed by successful yard testing. Field implementation was successfully completed by utilizing conventional slickline unit which saved significant time and cost. A standard SC-DHSV was redressed with the oversized B-Type seals, set in the landing nipple and functioned normally. The redressed SC-DHSVs were routinely tested during the following year with no concern reported. The successful implementation was documented and is recommended for future use in similar cases.
Well integrity, Downhole Safety Valve (DHSV) System, DHSV Landing Nipple Polished Sealbore Area, Risk Assessment, Workover, Rigless Application.
Ruksanor, Warakoon (Sakhalin Energy Investment Co. Ltd.) | Webers, J. (Sakhalin Energy Investment Co. Ltd.) | Vargas, E. (Sakhalin Energy Investment Co. Ltd.) | Gdanski, R. (Shell International Exploration and Production) | Vickery, S. (Shell International Exploration and Production)
Well LA-552 is the first Lunskoye horizontal oil rim appraisal/producer well targeting the oil rim underneath the Daghinsky gas reservoir. The well is a smart well completion having three zones (one gas zone for auto gas lift and two oil zones) remotely controlled by three inflow control valves (ICV's).
Pressure transient analysis on production data indicated a very high Darcy skin factor causing much lower production than expected. This was predominantly caused by overbalanced perforating with an oil-wet calcium carbonate (CaCO3) fluid-loss control pill used in the production liner.
Due to the well configuration, the damaged zones were not reliably accessible by wireline or coiled-tubing making re-perforation or acid jetting very difficult and risky. Without well recompletion, the only remaining option was to pump acid down the tubing through the ICV's to dissolve the pill across the long perforation intervals of both oil zones (approx. 200 meters long for each zone).
Zonal coverage (diversion) was expected to be a major challenge for an acid remediation treatment, since the perforations were behind tubing and accessible only through the ICV's. Various diversion methods were considered. Foam diversion in combination with a slow reacting acid system was selected to ensure zonal coverage.
An extensive series of lab tests were performed resulting in an acid blend of 9% formic acid containing 7% KCl (temporary clay stabilizer), 2.5% mutual solvent, 0.6% corrosion inhibitor, 15 lb/Mgal inhibitor aid, and 2% foamer being recommended for removal of damage believed to be oil-wet carbonate filter cake. The recommended acid was qualified as having passed oil-wet carbonate filter-cake dissolution tests, mud and oil compatibility tests, corrosion tests, and foam stability tests.
The acid stimulation was successfully performed in September 2011 with the following result:
Limited success for the lower zone. P.I. increased by 54% but no significant improvement seen in Darcy skin. The limited success of the lower zone could be explained by a combination of low injectivity (0.5 bpm) and operational challenges causing sub-optimum foaming.
The pdf file of this paper is in Russian. To purchase the paper in English, order SPE-156921-MS.
Cementing is one of important and crucial issues in oil field especially for high pressure and gas bearing formations. It is difficult to achieve a good zonal isolation in such formation types where pressure is abnormal and formation fluid contains corrosive fluids and gases. A common problem associated with highly over pressurized zones is cross flow after cementing. Fluid flow from an over pressured zone to a low pressure, high permeability zone can lead to deteriorating the existing production hardware. Work over operations that attempt to repair cement voids including perforation, squeezing and use of casing patches or scab liners are not recommended as they do not provide long lasting results. In one of onshore fields in Saudi Arabia there is a persistent problem related to cementing at high pressure zones. Recently, communication between A (abnormally over pressurized zone) and B (low pressure zone) formations is occurring due to long term sea water injection with increasing frequency, and has resulted in production interruption in several wells. This paper addresses the problems through investigating field practices including drilling, cementing, and completion. It also reviews the field reports and cased hole logs. A three-month study was conducted to evaluate the effects of formation-A water on cement, where the cement was exposed to formation-A water under down hole conditions. The tests for permeability, mechanical properties TGA and EDXRF are presented, in addition to discussions of some of the preliminary findings.
Recently the problems of the expansion of "smart wells?? in Russia are discussed a lot, but there are still only few real global achievements in this direction. The major reason of the delay of transferring well-known western technology "smart wells?? in Russian reality is its high unit cost. However an increase of hydrocarbons production and recovery from low permeable reservoirs using complex completion wells can't be achieved without moving to modern automated systems of «online» wells monitoring and layers control.