This paper focuses on an operational review and lessons learned during the deployment of a novel straddle packer system in a refracturing application. The operation involved the deployment of an industry-first high-rate / high-pressure straddle packer to convey a propped refrac job to a previously producing well in a challenging application. The paper will also include relevant notes on operational time optimization derived from the field implementation as well as pre and post-treatment production information.
The paper describes details on overcoming the challenge of effectively isolating a single group of perforations among multiple producing zones of a wellbore in order to deliver a targeted stimulation treatment. The paper also discusses opportunities for improvement and learnings from this novel deployment. Finally the paper analyzes pressure and temperature data gathered during the treatment to assist in understanding job execution as well as post-treatment production information.
The novel stimulation technology enabled the operator to accurately place a propped refrac treatment at 20 bpm in a 200ft-long interval of previously producing perforations in a single run. The application reduced the operational time on location by 30% and reduced the number of runs required to complete the operation. Comparative production results will be shown as a measure of treatment effectiveness.
The paper contributes a novel insight to the intervention, stimulation, and refracturing industries by describing one of the first successful high-rate re-stimulation jobs using a straddle packer with open perforations above and below in a single trip. This insight is relevant as it highlights a cost-effective alternative for reviving existing wells at a fraction of the cost of a new drill, without the need to deploy numerous tools and fluids in multiple trips to achieve the zonal isolation as typically required in a re-stimulation treatment.
Organic-rich mudrocks (ORM) from the Brushy Canyon Formation in west Texas were deposited in the Middle Permian during the Guadalupian epoch in the Delaware Basin. Brushy Canyon ORM were examined for Re-Os isotope systematics with a goal of constraining their depositional age, the 187Os/188Os value of seawater at their time of deposition, and to examine how Re and Os partition into organic material in ORM. For these samples, Rock-Eval pyrolysis data (HI: 228-393 mg/g; OI: 16-51 mg/g) indicates predominantly Type II marine kerogen with minor contributions of Type III terrestrial organic matter. Rhenium and osmium abundances correlate positively with HI, and negatively with OI, which are proxies for organic matter type and degree of preservation. These data are consistent with previous work that indicates Re and Os abundances are controlled by the availability of chelating sites in the kerogen. Brushy Canyon Formation samples have (total organic carbon) TOC values between 0.97 and 4.04% and show a strong positive correlation with both Re and Os abundances, consistent with correlations between these parameters in other ORM suites. The positive slopes in these correlations are distinct between marine (higher slopes) and non-marine (lower slopes) lacustrine environments of deposition. The Brushy Canyon’s steep slopes are consistent with marine deposition of its organic matter and an open-ocean non-restricted setting. The relationship to other Re-Os and TOC data sets appears to be a function of the restrictivity of marine conditions, and associated variations in reducing conditions during ORM accumulation of the Delaware Basin compared with more restricted lacustrine basins with local drawdown of Re and Os.
The Re-Os isotope systematics of ORM from the Brushy Canyon Formation yields a Model 1 age of 261.3 ± 5.3 Ma (2.0% age uncertainty; MSWD = 0.82). Within the uncertainty, this agrees with the expected Guadalupian age for this formation. This Re-Os age represents the first direct, absolute age for Guadalupian organic matter in the Delaware Basin. The initial (187Os/188Os)i = 0.50 ± 0.06 obtained by isochron regression represents the 187Os/188Os of seawater at this time. This value is significantly less radiogenic than modern day seawater (~1.06). The lower 187Os/188Os of Guadalupian seawater recorded is likely caused by a decrease in the relative flux of radiogenic Os from continental weathering due to a number of local and global climatic and tectonic changes that were occurring during this time.
Operators have successfully drilled horizontal wells to make unconventional plays profitable. The next step is to drill extended-reach laterals to maximize the profitability of each well. Not only are longer laterals difficult to drill, they can be challenging to complete economically. The specific problem this paper discusses is the completion method of an extended lateral with a low bottomhole pressure. The standard completion method in unconventional plays requires post-fracturing intervention in the form of drillouts, using fracturing plugs or ball-actuated frac sleeves.
Coiled tubing-actuated fracturing sleeves offer a new completion method that eliminates the need for post-fracturing intervention. These sleeves have been used in the United States due to their ability to enable operators to obtain an unlimited number of single-entry targeted fractures while not adding ID restrictions or more post-fracturing intervention.
Large-bore fracturing plugs are also a new completion method that eliminates the need for post-fracturing intervention. These fracturing plugs enable operators to use their current plug-and-perforate method without the need to drill out before production is started. The plugs can also be deployed to great depths that coiled tubing cannot reach, making them extremely useful in extended-reach laterals.
This paper will review the hybrid stimulation method used to complete an extended-reach lateral of over 10,000 ft. with a challenging well geometry. The completion consisted of seven plug-and-perforate stages and 32 coiled tubing-actuated fracturing sleeves, providing an interventionless completion.
To support the renewed interest in the hydrocarbon potential of the Labrador Sea, we have completed a regional seismic interpretation and integrated this with new biostratigraphic data, based on analyses of palynomorphs from wells in the Hopedale and Saglek basins. By integrating the two data-sets, we have developed a modified model for the evolution of the Labrador Margin. Our results are summarized in a tectonostratigraphic chart, which displays new and consistent age control for the major lithostratigraphic units and relates their depositional history to tectonic forces and global sea-level. Although we have identified and dated six regional unconformities in the wells, we can recognize several others on the seismic data. The older unconformities are related to the tectonics of rifting and seafloor spreading, and may delineate the onset of different stages of the rift process. In the Paleocene-Early Eocene, another significant influence was the episodic volcanism due to the passage of the proto-Iceland hot spot to the north, and to a major change in spreading direction in the Labrador Sea. During the post-seafloor spreading stage the effects of mass wasting and slumping, and of paleoenvironmental controls on the stratigraphy were more pronounced. We discuss the petroleum potential of the Hopedale Basin in terms of the structures we see on the seismic data, and highlight the Bjarni Formation, which appears to contain the most likely source and reservoir rocks.
Maddox, Bradley Dean (ECA Holdings, L.P.) | Wharton, Molly (Halliburton Energy Services Group) | Hinkie, Ronald Lee (Halliburton Energy Services Group) | Balcer, Brent Powell (Halliburton Energy Services Group) | Farabee, Mark (Ely & Associates Inc.) | Ely, John W.
This case-history paper presents an account of the application of expandable (swelling) packers and a hydrajet perforating stimulation technique to perform a cementless completion and hydraulic stimulation in a 350o F, openhole horizontal well of 15,700 ft total vertical depth (TVD). Resulting production was more than three times that of an offset vertical well.
The first Wilcox Meek 2 well in the Brazos Bell Prospect Area was drilled and completed to test the effectiveness of horizontal well technology in tight-sand formations. This paper presents the cementless completion process and explores the effectiveness of horizontal-well technology in tight sands by comparing initial horizontal-well production rates to those of offset vertical wells.
The well, which was the first horizontal Wilcox in the area and probably the deepest horizontal well completion for a sandstone reservoir in South Texas, used a 5 ½-in. / 3 ½-in combination string as a production string. The 3 ½-in casing was run in the openhole horizontal lateral section and extended into the 7 5/8-in liner casing. It employed five swellable packers, strategically placed on the string to facilitate isolation for optimum stimulation results. An additional swellable packer, larger than the previous five, was run on the top of the 3 ½-in casing string and was placed inside the 7 5/8-in casing to help ensure complete isolation of the annulus. The swelling packers were activated over an 18-day period by hydrocarbons present in the oil-based mud (OBM) in the annulus.
Following packer activation, four fracture-stimulation operations were conducted in a non-cemented hole using a unique fracturing technique that incorporates hydrajet perforating with coiled tubing (CT). This technique allows for (1) multiple stimulation treatments to be performed in series without the CT being removed from the hole, (2) larger stimulation stages, and (3) maximum surface-area exposure to the fracture pressure without formation damage caused by cement.
Hydrajet fracturing, a relatively new stimulation technology for horizontal completions, has already proven successful in oil and gas wells across three continents. This multistage fracture stimulation method has primarily used jointed pipe to achieve hydraulic fracturing injection rates. The recent introduction of large OD coiled-tubing (CT) to the process has improved operating flexibility, reduced job time, and significantly enhanced health, safety, and environmental (HSE) performance. For some operations, it can also provide cost savings.
Before 2003, most CT-conveyed applications of this process typically were limited to hydrajet-assisted acid-squeeze injections, with only a few low-rate acid-frac treatments performed. By using larger-OD coiled tubing, operators have placed propped fracture treatments to approximately 8,000 ft measured depth (MD) at treating rates up to 10 bbl/min.
The use of a combined workstring consisting of jointed pipe connected to a surface string of CT can enable these multi-stage treatments to be placed in much deeper reservoirs, effectively doubling or tripling the depth capability of a CT-deployed treatment. For many applications this capability would provide the flexibility, speed, and safety inherent to coiled-tubing operations with a spool of only a few thousand feet, and jointed pipe would not be exposed to high treating pressures at the surface.
This paper reviews several field applications where coiled tubing was used to deploy hydraulic jet fracture treatments. One field case is compared directly to an earlier treatment in the same reservoir, which had been pumped through jointed pipe.
Jordan, Jeff S. (APEX Petroleum Engineering) | Harkrider, John D. (APEX Petroleum Engineering) | Anthony, William L. (APEX Petroleum Engineering) | DeLong, Thomas W. (XTO Energy Inc.) | Martin, Ray F. (XTO Energy Inc.)
This paper describes an innovative fracture treatment design approach that has been successfully used to improve the productivity of Fruitland coal CBM completions. The process integrates real-time treating pressure evaluation to adjust key treatment parameters on the fly and maintain a low net pressure development. The low net pressure development indicates good proppant distribution through the created fracture geometry and minimizes potential formation/fracture damage from the fracturing fluids. This results in shorter de-watering periods and accelerates peak production of the Fruitland Coal completions.
In the Fruitland Coal, the dominant fracturing mechanism controlling the ability to distribute proppant laterally into the far-field is the quality of the near-wellbore connection. Complex near-wellbore fracture geometries result in a convoluted slurry pathway, which hinders lateral proppant distribution into the far-field. Further, if the near-wellbore connection was not mitigated effectively, the overall net pressure development while placing proppant became excessive. This paper discusses the innovative changes made to improve the near-wellbore connection, allowing the treatment to be completed and productivity of the well increased.
Based on an offset well study, it was observed that excess net pressure development damaged the fracture conductivity and/or the cleat system of the coal. When an excessive level of net pressure was developed, polymer dehydration into the cleat system caused irreparable damage to the existing permeability. Evidence of the damage was indicated by the extended load fluid recovery time. Since de-watering of the coal begins only after the load is recovered, it was observed that gas production was significantly delayed when the net pressure development during the propped fracture treatment was excessively high.
Observing this relationship, treatment designs were altered, but more importantly, real-time assessment of the treatment pressure character was found to be essential in achieving design objectives. The completion approach discussed in this paper has been employed in over thirty-five Fruitland Coals completions over the past three years with excellent production results.
The Delaware formation is a fine grained sandstone located in West Texas and Southeast New Mexico. Resistivity- based log interpretation in this formation has proved unreliable in many cases. In particular, deep invasion and high irreducible water volumes result in calculated water saturations that rarely reflect future production. Because of this, pay zones are identified primarily from mud logs and sidewall cores. However, our studies have demonstrated that borehole nuclear magnetic resonance (NMR) measurements are useful for evaluating the Delaware formation. The general use of NMR measurements for the estimation of porosity, pore size, permeability, producible porosity and bound-fluid volume and for the identification of pay zones has been previously described.
Often, the interpretation of borehole NMR data is enhanced by the results of lab NMR measurements on core samples. For this reason, NMR measurements were made on 20 water-saturated cores, a crude oil sample from the Delaware and a partially oil-saturated core sample.
Water-saturated samples have narrow T2-distributions and maximum T2 values in the order of 200 ms. A typical distribution is shown in Figure la. The relatively short T2 values reflect the fine grains and small pore sizes typical of this formation. However, significant pore size variation between the samples results in a generally poor correlation between permeability and porosity. Permeability estimation is improved when an NMR parameter, such as logarithmic mean T2 or bound-fluid volume, is used together with porosity. Lastly, NMR free-fluid porosities were found to be in good agreement with the volume of water expelled from the core by centrifuging at 100-psi air-brine capillary pressure. The free-fluid porosities were computed from the T2-distributions using a 33-ms cutoff.
T2-distributions for the crude oil and a core sample partially saturated with the crude oil are shown in Figures 1b and lc. T2 values for the crude oil are long, predominantly in the 100 to 5000 ms range, reflecting the low viscosity of the oil. For the partially oil-saturated sample, T2-distributions were found to be considerably broader than for the case when the sample was completely saturated with water. Maximum T2 values increased from 200 ms to about 1000 ms. In addition, the mean T2 and also the free-fluid and bound-fluid porosities are significantly different when the sample is partially oil saturated; hence, permeability estimation using these parameters will be affected by the presence of oil.
NMR logs were recorded in the Delaware formation in four wells (A, B, C and D) located in Southeast New Mexico. The wells were logged with either the NML Nuclear Magnetism Logging tool or CMR Combinable Magnetic Resonance tool.
For Well A, irreducible water volume and permeability estimates from the NML log were in good agreement with core data and subsequent production, except in thin-bed intervals where the vertical resolution (about 4 ft.) of the NML log is inadequate. NML station logs were also successful in differentiating between known oil and water zones.
For Well B, T2-distributions from CMR station logs were used to identify oil-productive intervals. As observed with the lab measurements, water-saturated intervals have T2-distributions that end at approximately 200 ms whereas oil bearing intervals have maximum T2 values on the order of 500ms.
Oil bearing intervals may also be identified from T2-distributions obtained during continuous depth logging with the CMR tool. Figure 2 shows a comparison between CMR data and the total gas measurement from a mud log obtained in Well C.
Ouenes, Ahmed (Petroleum Recovery Research Center) | Weiss, William (Petroleum Recovery Research Center) | Sultan, A.J. (Abu Dhabi Natl. Reservoir Research Foundation) | Anwar, Jabed (Petroleum Recovery Research Center)
This paper describes a new computing environment for reservoir automatic history matching. A parallel simulated annealing algorithm is used to estimate geologic and reservoir engineering parameters by automatically matching production history of an actual oil reservoir. A complex computer set-up using two networks of workstations simultaneously, located at the New Mexico Petroleum Recovery Research Center (PRRC) and the Los Alamos National Laboratory (LANL), is used to test the concept of distributed optimization. A heterogeneous cluster of two workstations (HP and SUN) is used at the PRRC and a homogeneous cluster of six IBM RISO 6000 workstations is used at LANL. At each site (PRRC and LANL), a Parallel Virtual Machine is created by using the message passing software, PVM. Communication between the two parallel virtual machines located at the PRRC and LANL is achieved with a simple e-mail protocol. In this new environment, the total time required to complete a 22 well oil reservoir study lead to the following observation: two-thirds of the time was devoted to geologic, core, and well log analyses, and one-third of the time to history matching.
After a few years of applying stochastic modeling to petroleum reservoirs, researchers and engineers have begun to realize that geostatistics is not enough in describing oil and gas reservoirs. Consequently, a new trend, using both deterministic and stochastic reservoir modeling techniques, recently emerged. Besides this mixed approach, there are two extreme positions in this area. The first one, is represented by those who are convinced that the use of stochastic modeling is the only viable approach in reservoir description. The second one, is represented by those who believe that a probabilistic description is not appropriate at all in reservoir modeling. In this old debate, the only important point is the fact that the uncertainties in reservoir description can be reduced when reservoir models honor all the existing field data.
Some of the most important information from petroleum reservoirs is the dynamic data such as pressure and production history. For many years, geoscientists have produced grayscale maps and 3-D models representing various stochastic models. However, the reservoir engineering value of such realizations were very often poor and in many instances unable to match the cumulative field production. Because of this deficiency, an effort has been initiated to add more constraints to the stochastic models. The application of global optimization methods to reservoir description have provided a framework where this objective is achievable. The goal of this approach is to constrain reservoir models with available dynamic field data. Today, it appears that pressure history obtained during well-test is becoming the major focus of this research area, and little attention is given to production history.
Constraining reservoir models to production history is the ultimate objective of reservoir engineers. Unfortunately, the practice of adjusting relative permeability curves and permeability in a few gridblocks around the wells rarely provides reliable reservoir models. On the other hand, the experience of the petroleum industry with automatic history matching algorithms has lead many engineers and researchers to believe that such techniques are impractical. As a result, the research in this area has been drastically reduced, almost to extinction, with only a few exceptions.
There are two main components in an automatic history matching algorithm: the first one is the optimization method, and the second one is the available computation power. Both components have recently seen dramatic changes, and will continue to be the subjects of a rapid evolution.