In the Danish Central Graben, tight chalk reservoirs have been successfully developed through drilling, completion and stimulation of long horizontal wells. One of the most successful technologies which has opened access to the far reaches of several major fields is the Controlled Acid Jetting (CAJ) technique. CAJ treatments are performed with a treatment pressure at formation below fracturing pressure and at the maximum rate possible. Diversion is via maximum rate/pressure, combined with the limited entry technique; therefore diversion stages are not normally included in CAJ treatments. A horizontal CAJ completion may range from 5,000 ft to as long as 20,000 ft, but is most often on the order of 10,000 ft. Acid coverage is normally 1 bbl/ft of 15% HCl. Injection rates as high as 40-50 BPM are often required to ensure complete coverage of the CAJ liner. There are still areas to be investigated to maintain an effective optimization of the CAJ technology. One of these areas to be investigated is the frictional pressure drop across the perforations (ΔPperf), which is influenced by the perforation coefficient (Cp). Usually in the design and operation of the stimulation, Cp is assigned a specific value when calculating the pressure drop across the perforations. Field experience and previous studies discovered that the Cp may change due to the viscosity of the fluid injected. This paper will present the results of a study of the perforation coefficient through laboratory experiments. A set-up for measuring the pressure drop across an orifice for different types of fluids at different flow rates was constructed. The perforation pressure drops were measured and then used to calculate the fluid specific Cp in order to clarify any changes in relation to the viscosity. The results of the laboratory study are utilized in a real-time CAJ stimulation diagnostic tool which has been used in several different chalk formations. The predicted acid coverage of the long CAJ liners is shown to be very sensitive to the assumed value of Cp. Overall, the outcome of this project was considered as a further contribution to the process of achieving a better understanding of the CAJ stimulation in general and about the impact of the perforation coefficient in specific.

Productivity enhancement of tight carbonate reservoirs (permeability 1-3 md) is critical to deliver the mandated production and to achieve the overall recovery. However, productivity improvement with conventional acid stimulation is very limited and short-lived. Tight reservoirs development with down spacing and higher number of infill wells can increase the oil recovery. Nevertheless, poor vertical communication (Kv/Kh < 0.5) within the layered reservoir is still a challenge for productivity enhancement and needs to be improved. First time successful installation of fishbone stimulation technology at ADNOC Onshore targeted establishing vertical communication between layers, in addition to maximizing the reservoir contact. Furthermore this advanced stimulation technology connects the natural fractures within the reservoir, bypasses near well bore damage and allows the thin sub layers to produce. This technology requires running standard lower completion tubing with Fishbone subs preloaded with 40ft needles, and stimulation with rig on site. This paper presents the case study of the fishbone stimulation technology implemented at one of the tight-layered carbonate reservoir. A new development well from ADNOC Onshore South East field was selected for implementation of this technology. The well completion consisting of 4 ½ liner with 40 fishbone subs was installed, each sub containing four needles at 90 degrees phasing capable of penetrating the reservoir up to 40 ft. While rig on site, acid job was conducted for creating jetting effect to penetrate the needles into the formation. Upon completion of jetting operation, fishbone basket run cleaned the unpenetrated needles present in the liner to establish the accessibility up to the total depth. Overall, application of this technology improved the well production rate to 1600 BOPD compared to 400 BOPD of production from nearby wells in the same PAD and reservoir. In addition the productivity of the candidate well improved by 2.5 times with respect to near-by wells in the same PAD. Currently, long-term sustainability testing preparation is in progress. This paper provides the details of candidate selection, completion design, technology limitations, operational challenges, post job testing and lessons learned during pilot implementation. In summary, successful application of this technology is a game changer for tight carbonate productivity enhancement that improves the overall recovery along with optimizing the drilling requirements. Currently, preparation for implementation of 10 pilots in one of the asset at ADNOC Onshore fields is in progress.

In the Danish Central Graben, the Lower Cretaceous reservoir contains significant in-place oil volumes. This formation historically has posed a real challenge to develop because of the extremely low permeability. The low permeability is compounded by the fact that the formation is soft, highly heterogeneous, and can have significant clay content in some areas. Although the Lower Cretaceous chalks represent a wide spread play in the central North Sea, there are no producing analogs. Thicker Lower Cretaceous reservoir sections in the Valdemar field have been successfully proppant fracture stimulated. Acid stimulation is preferred for the thinner sections; however, early attempts at matrix acid stimulation were very disappointing. Recently, the need to re-enter a well for maintenance allowed three zones to be selectively restimulated using improved execution techniques and a more appropriate acid formulation. Production increase following restimulation of this first well was very encouraging and the lessons learned were applied to a second well; this time a newly drilled well completed in the Tyra Lower Cretaceous reservoir. This paper summarizes the lessons learned, starting with a review of the previous acid stimulations. Wormhole testing with Lower Cretaceous core material provided important insight toward the selection of the most appropriate acid formulation. Computer modeling was used to determine the most effective perforation patterns, based upon variable formation characteristics along the long, horizontal wellbore. Treatment execution and monitoring included diagnostic injection tests and real-time calculations of acid coverage during the limited-entry perforated completions. The results of these two wells has been very encouraging and has opened up the possibility for continued testing of acid stimulation techniques in both the Valdemar and Tyra Lower Cretaceous reservoirs.

Fishbone Stimulation Technology was developed to increase the well productivity from the tight reservoir for maximum hydrocarbon recovery. Additionally, this technology was implemented in a thin reservoir where conventional stimulation techniques have not been effective and very risky for more aggressive stimulation technique such as hydraulic fracturing. The application of Fishbone Stimulation Technology was the first time experience representing a massive uncertainity. Thus, a multidisplinary team was estasblished, including members of different departments of the operator and contractors, to design the operational procedures, conduct risk assessment, contingency plans, technical requirements and technical limitations. this first implementation of the fishbone stimulation in ADNOC Onshore served as the benchmark and reference for other fishbone candidate wells in ADNOC Onshore and other ADNOC subsidiaries. The deployment of the equipment and the production results were a complete success overcoming the risks and previously mentioned uncertainities, closing some gaps from previous partial effective applications in other companies. The Fishbone stimulation technology will help to increase the well productivity via below mechanism in a well that is too risky to be hydraulically fractured and beyond the coiled tubing reach: Extension of the needles to connect natural fractures and vertical layers (for reservoir with poor Kv/Kh) Increase reservoir contact Sweep Efficiency of the reservoir

Bokor field was selected as the first field in Malaysia for Microbial Enhanced Oil Recovery (MEOR) technology application which utilizes micro-organisms to facilitate, increase or extend oil production from reservoir through the production of biochemical such as biosurfactant, solvents, gases and weak acids. The field was selected due to its high viscosity crude (4 to 10 cp) and low oil specific gravity of 20° API which could resulted in low recovery factor in major reservoirs ranges from 19% to 25% of its original oil in place. This technology also seems to be attractive for the field as it was initially thought to be potential for for reducing the viscosity of the oil and thus improve oil recovery. In addition, reservoir properties for major reservoirs in Bokor field conform to the basic screening criteria of the MEOR application. This paper mainly discusses the results of the pilot project on MEOR technology application in Bokor field1. A feasibility study focusing on candidate selection and comprehensive laboratory analysis was conducted to investigate the feasibility of this technology for improving oil production/recovery. Generally, the feasibility study had indicated that there is a potential oil production improvement with no near wellbore impairment. Biodegradation study on the crude sample indicates complete removal of normal/branched alkanes and partial removal of aromatics due to in-reservoir alteration. Laboratory inoculation on the wellhead crude sample indicated that the microbes were able to slightly reduce the viscosity, break the emulsion and increase the solubility of high molecular weight component without damaging the reservoir. In order to prove the laboratory results and further assess the impact to oil production, a pilot test on three (3) selected wells were carried out. A comprehensive monitoring strategy was developed and the performances were monitored for 5 – 6 months. Over 5 months period, results from the pilot were found to be encouraging. Significant increase in oil production rate and reduction of water cut were observed demonstrating the effectiveness of MEOR application. The average oil production rate for the period increases by 270 b/d which is equivalent to 47% oil incremental. Overview of MEOR Technology Microbial Enhanced Oil Recovery (MEOR) is a technology using micro-organisms to facilitate, increase or extend oil production from reservoir. The concept is more than 40 years old, however, early proposals were poorly conceived and in most cases had no practical value. Recent studies have developed microbial biotechnology to resolve specific production problems in reservoir. MEOR processes involve the use of in-reservoir micro-organisms or specially selected natural bacteria which are capable of metabolising hydrocarbons to produce organic solvents, like alcohols and aldehydes, fatty acids surfactants and other biochemical that are known to be effective at encouraging oil mobility.