There is a very significant move today towards multiple zone fracturing operations in a single well where zones are separated and individually fractured, particularly in shale gas completions. This technique has to date involved the use of ball seat activated sliding sleeves located across each zone, with consequent reductions in internal diameter (ID) and attendant flow characteristic limitations or selective perforating, fracing and isolation with a bridge plug in a cemented casing string while working up the hole. Both approaches involve many downhole intervention operations such as perforating, shifting sleeves, running plugs and subsequently milling them up with coiled tubing (CT) intervention, all of which extend the length of the operation and add to the overall costs.
To simplify the process of multiple fracturing operations, especially in open hole, a new approach has been designed which uses Radio Frequency Identification (RFID) techniques to remotely operate sliding sleeves. The number of sleeves that can be run in a well using this technology is essentially unlimited, each one having the same ID and a unique electronic address which allows it to be operated remotely at will. This approach provides for a means of making considerably more zones available for treatment without physical intervention with CT or wireline and thereby speeds the multiple frac operations and allows for wellbore clean up from the toe to the heel of the well.
In this paper the authors will describe the design and operation of the RFID operated frac sleeves and the advantages they provide. They will go on to detail the Worlds' first remotely operated horizontal openhole frac completion where frac sleeves and swell packers were used in an extended reach horizontal shale gas well.
Exploration for shales has become an integral part of many operators' processes in the North American shale boom. While leveraging public data in existing plays is a major advantage, when looking outside those existing areas, a comprehensive plan must be developed. The shale-exploration methodology is fundamentally different from conventional exploration, with different drivers and metrics.
Shale exploration requires an exploration program that includes a heavy data-acquisition element. Beyond the initial geological identification of the prospect, wells need to be drilled to evaluate the potential of the shale prospect. Extensive coring, open-hole logging and formation pressure testing are required to answer four basic questions: Does the shale have enough total organic content? Does the shale have the thermal maturity necessary? Does the shale have the stimulation potential? Does the sale have a simple structural environment conducive to horizontal drilling? Once these questions have a satisfactory answer, the key shale properties can be mapped using multiple sources with the goal of identifying core areas suitable for further horizontal well evaluation.
This paper describes the process and workflow for a data-acquisition program and demonstrates not only the benefits of acquiring specific data, but also highlights the uses of the data to aid the exploration decision process. Examples are given of the type data acquired, and the analytical workflow is discussed.
Recent work has shown the potential usefulness of magnetic susceptibility and hysteresis techniques in assessing the impact of fine grained hematite on permeability in red and white sandstone samples (Potter et al. 2009; Ali and Potter, 2011b). The present study demonstrates that hematite cementation is a major controlling factor on permeability in a deep tight gas reservoir in the North Sea. Magnetic susceptibility measurements undertaken on core plugs in this reservoir showed a strong correlation with probe permeability performed on the same plug samples. Moreover, samples with a higher content of hematite exhibited lower permeability values. Thin section analysis revealed the presence of a thin (approximately 10-15µm) rim of hematite cement surrounding quartz grains, which block pore connections and reduce permeability.
Magnetic hysteresis measurements on some representative samples indicated a very similar paramagnetic clay content in both the low and high permeability samples suggesting that the clay (mainly illite) is not the dominant controlling factor producing the variations in permeability that we observed. Since samples with higher hematite content exhibit lower permeability it appears that hematite is a major control on the permeability variations seen in this reservoir. Whilst the paramagnetic clays undoubtedly have an influence on the absolute permeability value, since increasing paramagnetic clay content has previously been shown to correlated with decreasing permeability (Potter, 2007), small amounts of hematite cement can significantly further reduce the permeability. Analysis of the magnetic hysteresis parameters on a Day plot indicated that the permeability was essentially independent of the hematite particle size for the fine particle sizes observed in this study.
Flores, Vincent Pierre (VAM Drilling) | El Bachiri, Kamal (VAM Drilling) | Fei, Li (Zhongyuan Drilling Services, Sinopec) | LI, Fei (Sinopec - Zhongyuan Oilfield Drilling Services) | Zhang, Da (Zhongyuan Drilling Services, Sinopec)
Puguang region is known for containing sour fields with significant amount of H2S. Since 1975, sour service wells have been drilled entailing critical drilling conditions. To optimize drilling efficiency without sacrificing security, drill string improvements have been always looked for, by carefully evaluating steel grades, drill pipe sizes and connections.
The evolution of drilling programs has driven the industry to develop more suitable solutions adapted to extreme and aggressive conditions such as Sour Service environments. High strength drill pipe is often necessary to achieve deeper drilling performance, even when Sulfide Stress Cracking susceptibility is observed in minimal concentrations of H2S in partial pressures. Due to the astringency of the sour environment, particular precautions have to be defined to select and
characterize an adapted Sour Service steel grade.
This paper presents the evolution of choices in drill string design from basic API grades and connections to adapt and proprietary steel grades resistant to H2S with a high mechanical performance properties and high torque double shoulder connections.
Jasem Al-Saeedi, Mohammed (Kuwait Oil Company) | Al Fayez, Fayez Abdulrahman (Kuwait Oil Company) | Rasheed Al Enezi, Dakhil (Kuwait Oil Company) | Sounderrajan, Mahesh (Kuwait Oil Company) | Saxena, Ashok (Kuwait Oil Company) | Chimirala, Vivekanand (Schlumberger D&M - Kuwait) | Mckinnell, David Charles (Total)
Recent drilling activities in the State of Kuwait have focused on the search for high quality oil from the Jurassic formations. The wells drilled to these prospects are very challenging because of HPHT conditions, presence of high levels H2S and CO2, and narrow pore/fracture pressure windows.
The targeted Jurassic formations are the Najmah-Sargelu and Middle Marrat, which are located below the Gotnia salt/anhydrite. These reservoirs consist of layered shales and limestones, which can be highly fractured. One of the main challenges in the effective development of these reservoirs is the ability of the wells to access a permeable interconnected vertical fracture network. Horizontal well profiles increase the probability of crossing multiple fractures or fracture swams, resulting in high productivity and reserve recovery per well.
A ‘Conceptual Project' was set up with the objective to design the first horizontal well to be drilled through the Najmah reservoir, in the North Kuwait fields. The challenges included; the establishment of an optimum well trajectory, drilling through the mobile salt section of the Gotnia at well inclinations above 60º, planning a pilot hole in the reservoir section to facilitate positioning of the lateral, identifying suitable water base mud system to improve image log quality, planning a high DLS openhole sidetrack just below 10 3/4" casing shoe and introducing a casing string (just above lateral) to address borehole stability concerns.
To address these challenges a team based approach was established between operator and contractors, to develop the well design, detailed engineering and operational procedures. This paper will describe the methodology adopted during this well design process and the technical challenges faced and overcome.
Knowledge of the magitude and direction of the three principal in-situ stresses is critical for performing wellbore stability analysis in order to optimize the mud weight program for drilling. In vertical wells, breakouts tend to occur parallel to the minimum horizontal stress direction, and the sonic fast shear azimuth (FSA) coincides with the direction of maximum horizontal stress. However, for arbitrary well deviations, breakouts and the FSA are not oriented 90 degrees to each other. Breakout orientations in a deviated well depend on well trajectory as well as in-situ stress magnitudes and orientations, which can vary from the scale of the regional to the well scale. We present a case study from western offshore, India, where breakouts associated with different well orientations were used to determine the in-situ stress regime and minimum horizontal stress direction. In addition, the stress-induced sonic fast shear azimuth at different well orientations was determined and analyzed using dispersion plots. The horizontal stress anisotropy was confirmed with crossover behavior on the fast shear -slow shear profile. Because the sonic fast shear azimuth and the breakout direction are complementary, careful evaluation of change in their orientation with well deviation improved inferred stress directions. The study concludes that a strike-slip stress regime (sH > sv > sh) exists, which is different from the previously determined stress regime. We further demonstrate that once stress state and stress directions are determined, wellbore stability analysis using a mechanical earth model (MEM) can be performed more accurately. In this study, a post-drill MEM that comprises rock mechanical properties, stress tensors, and pore pressure was used to investigate the causes of overgauged holes and drilling problems that occurred in the deviated wells in this region.
In the last decade, shale resource exploitation has transformed North American production capacity through technological improvements in horizontal drilling and the ability to efficiently stimulate horizontal wellbores using multiple hydraulic fractures. The 2011 U.S. Energy Information Administration estimates there are unproved, technically recoverable shale gas resources of 827 Tcf (in addition to 20.1 Tcf of reserves) in the USA alone. Exploration and exploitation of Middle East
organic-rich shales are just beginning, and discovery of economically viable resources requires a concerted effort. While Middle East resources in place could be much greater than those in North America, "sweet spots?? need to be found in which established source rocks can also function as reservoirs. Evaluating these opportunities requires refined reservoir characterization workflows rather than the statistical approach that characterized early development of North American shale plays, which benefited from high gas prices, numerous existing wells, and infrastructure to support drilling and fracturing.
With lower well density and higher well costs than in North America, successful exploration for unconventional hydrocarbon resources in the Middle East will necessarily rely more on modeling.
A petroleum systems-oriented approach defines sweet spots by predicting reservoir quality and potential completion quality. Using proven and effective tools, sweet spots are identified early in the life of unconventional plays. Since reliable, comprehensive data concerning the behavior of shale resource systems under varying conditions are not widely available in the Middle East, petroleum systems modeling would yield key risk and value information.
Standard petroleum systems modeling tools have recently been improved, providing more accurate results based on experience of modeling unconventional plays. By extending traditional basin and petroleum systems modeling with sophisticated adsorption functionality, the modeling of hydrocarbon adsorption on kerogen and primary migration within tight source rocks has been significantly enhanced. These methods have the potential to improve the efficiency and effectiveness of Middle East shale resource evaluation.
Azizov, Azar A. (Baker Hughes) | Davila, Wilfredo (Baker Hughes Inc.) | Janwadkar, Sandeep Shashikant (Baker Hughes) | Fabian, John A. (Baker Hughes) | Fortelney, Ryan (Baker Hughes Inc.) | Welch, Bart (XTO Energy)
The US-land unconventional shale plays have initiated an exponential increase in the number of horizontal wells drilled and completed in the last decade. Maximizing well productivity and improving drilling efficiency has always been a major challenge. Well placement in the sweet spot and extended laterals help maximize productivity. Curve intervals drilled with higher dogleg severity (DLS) have a reduced vertical-section which maximizes the length of subsequent lateral section in the productive zone. Wells in US shale plays are usually drilled with a DLS of 10 to 14 °/100 ft, but achieving high DLS presents numerous drilling challenges: rotating a steerable motor with a high adjustable kick-off sub (AKO) angle could result in bottomhole assembly (BHA) fatigue failure and premature damage to bit; drilling in oriented (slide) mode limits weight transfer to the bit which may reduce the rate-of-penetration (ROP).
These challenges led to the development and successful testing of a new steerable optimized design motor (ODM) with a short bit-to-bend (BTB) distance. In some cases, the ODM motor drilled all sections, including high-DLS curves, tangents and laterals with precise directional control and well placement with one BHA. The ODM has helped the operator to achieve higher DLS at lower AKO angle settings, enabled rotating the BHA in well profiles where previously used motors could be operated only in slide mode and maximized the length of curve interval drilled in rotary mode at higher RPMs. Drilling high- DLS curves increased the length of laterals, enabling additional recovery of gas. The new system significantly improved drilling performance with excellent directional control.
This paper will discuss the design, modeling and results of horizontal type wells drilled using the steerable ODM in the Fayetteville Shale unconventional play.
Technological advances and improved operational efficiency have made unconventional resources around the globe far more lucrative for producers. The challenge in recovering hydrocarbons from unconventional resources is low permeability, making it essential that a cost-efficient fracture-stimulation treatment program be performed. However, while the wells being completed are economical, are operators truly capitalizing on their full potential?
The process of fracturing unconventional reservoirs has remained virtually unchanged in recent years. Stimulation treatments are pumped at high rates through multiple perforation clusters over a large interval and isolated using mechanical plugs. This poses several problems:
- Uncertainty of the number of fractures created.
- Uncertainty of proppant placement into fractures.
- Costly and time-consuming recovery from screenouts.
- Pumping plugs results in overflushing the near-wellbore.
- Treatment changes cannot be seen at the perforations until a casing volume is pumped.
- Increased cost, footprint, personnel, and hydraulic-horsepower (HHP) requirements.
This paper presents a high-rate coiled tubing (CT) fracturing technique that enables customized fracture treatments to help maximize stimulated reservoir volume (SRV) by manipulating flow rate and proppant concentration at the perforations in response to reservoir pressure. Therefore, every gallon of fluid and every pound of proppant can be used to effectively stimulate the formation. Recovery from screenouts is fast because of having coil in-hole, but the functionality of the process enables screenouts to be avoided all together. At the end of the treatment, the well is simply cleaned out, and the entire operation is completed with only one trip in hole and with no plugs to be drilled out. These benefits combined can maximize return on investment for the operator. This paper includes a side-by-side comparison of this technique with a conventional fracturing treatment, weighing risk, stimulation effectiveness, operational efficiencies, and cost savings.
Tight gas reservoirs show challenges to geologists to characterize because of their tendency to be generally heterogeneous due to depositional and diagenetic processes. The value petrophysical properties are very valuable in static and dynamic reservoir modeling. This paper presents a prediction of Klinkenberg permeability by using artificial neural network, composite logs and core data in basin in western USA. The klinkenberg model approximates a linear relation between the measured gas permeability and the reciprocal absolute mean core pressure. This model has been a consistent basis for the development of methods computing the absolute liquid permeability of a core sample based on a single data point.
In tight gas reservoir with increasing in gas slippag ( klinkenberg effect) cause to decrease in pore-throat size and permeability parameters. In advanced there were some method to determine Klinkenberg permeability in situ which can be obtained by measuring just routine air permeability and Klinkenberg parameter such as byrnes in 1997 & 2003 but these ways intensively depend on core permeability, so it needs some core plugs and inevitably we have to spend much time and money.
The goal in this study was to research about relationship between core Klinkenberg permeability and composite logs (gamma ray, density, neutron and formation resistivity and so on) by using MLP & Back Propagation methods (Artificial neural network) to characterize the Klinkenberg permeability in situ in 3 different wells in 3 stages (training, validation and application) with suitable core calibration. For two wells there is very good core calibration and the R2 is more than 0.7 in training and application processes.
The importance of evaluation of tight gas reservoir with high heterogeneity by using artificial neural network and conventional logs is spending less capital or time and finally obtaining reliable Klinkenberg permeability in situ.