This study analyzes the production data from 2,755 horizontal wells in the Haynesville shale. Correlations were generated to predict 4,5,6, and 7-year cumulative productions from initial 6,12 and 24-months production data. These correlations can help in field development planning and economic analysis. The residuals (Predicted – Actual Cumulative Production) from these correlations were also analyzed and this technique can be used to identify wells affected by interference, refracturing, frac-hits, etc.
The cumulative production estimates from the developed correlations were also compared with the corresponding estimates from the DCA equations (seven different DCA methods used). The accuracy of prediction based on correlations developed in this study is at par with the various standard DCA methods published and used in the industry. The correlations are much faster to use and easier to implement for a large number of wells.
Another objective of the paper was to develop P10, P50 and P90 type curves for the Haynesville shale using the available production data. A subset of the total wells i.e. 150 wells evenly distributed throughout the study area, were used for predicting type curves. These type curves were generated and compared using different Decline Curve Analysis (DCA) models. The different DCA methods predicted an uncertainty of 5 to 27 % for the P10, P50 and P90 production profiles.
Ely, John W. (Ely & Associates Corp) | Harper, Jon (Ely & Associates Corp) | Nieto, Esteban N. (Ely & Associates Corp) | Kousparis, Dimitrios (Paris Oil and Gas Corporation) | Kousparis, Andrew (Paris Oil and Gas Corporation) | Crumrine, Curt (W.B. Osborne Oil and Gas Corporation)
The Northern extension of the "COMBO" Barnett Shale is located primarily in Montague, Cooke, and Clay counties in the North Texas region. This play is unique in that the shale in the area is very rich in total organic content (TOC) and contains a relatively high concentration of carbonates throughout. This extension is primarily inside the the oil window of the Barnett, rather than predominately within the more gas-rich region, which dominates the rest of the shale's development throughout North Texas (See
One of the Wolfcamp's most active operators, the Houston independent has more than 3 billion BOE in estimated recoverable resources in the play. US proved reserves of crude oil and natural gas reached all-time highs at yearend 2017, as higher commodity prices encouraged more drilling and expanded the scope of what operators deem economically recoverable. Accounting for lease condensate, proved reserves were just under 42 billion bbl, up 19% year-over-year. Proved gas reserves were 464.3 Tcf, a 36.1% spike from a year earlier and well-above the 2014 all-time mark. Owing to the unconventional boom built on horizontal drilling and hydraulic fracturing, both oil and gas totals are twice their levels compared with a decade ago.
In anisotropic rocks such as shale, the value of the maximum principal stress required to cause shear failure depends not only on the other two principal stresses, but also on the angle β between the maximum principal stress and the normal to the bedding plane. According to Jaeger’s plane of weakness model, for β near 0° or 90°, failure will occur at a stress determined by the failure criterion for the “intact rock”, and the failure plane will cut across the bedding planes. At intermediate angles, failure will occur along a bedding plane, at a stress determined by the strength parameters of the bedding plane. Data were analyzed from a set of triaxial (σ2 = σ3) compression tests conducted on a suite of shale samples, at different confining stresses, and a range of angles β and it was found that the data could be fit reasonably well with the four-parameter plane of weakness model. Based on these results, a model has been developed for the stability of boreholes drilled in shales. The fully anisotropic Lekhnitskii-Amadei solution is used to compute the stresses around the borehole wall. The Mogi-Coulomb failure criterion is used for the strength of the “intact rock”, and the plane of weakness model is used for the strength of the bedding planes. The model can be used to predict the minimum mud weight required to avoid shear failure, for arbitrary borehole orientations and anisotropy ratios. The results show the importance of using a fully anisotropic elastic model for the stresses, and using a true-triaxial failure criterion, in borehole stability analysis.
A fundamental problem in rock mechanics is to predict, based on the stress state, whether or not a rock will “fail”. There are several modes of failure, one of the most important being shear failure, in which the initially intact rock breaks along a plane whose orientation is controlled by the orientations and magnitudes of the principal stresses. For isotropic rocks, the simplest and oldest failure criterion is the Coulomb failure criterion (Jaeger et al., 2007), which states that failure will occur if and when
where σ1 ≥ σ2 ≥ σ3 are the three principal stresses, So is the cohesion, Co is the uniaxial compressive strength, β = 45°+(ϕ/2) is the angle between the normal vector to the failure plane and the maximum principal stress, ϕ = tan−1 μ is the angle of internal friction, and μ is the coefficient of internal friction. Many other shear failure criteria have also been proposed (Jaeger et al., 2007; Labuz et al., 2018).
Bayer, W. Sebastian (BHP Billiton Petroleum) | Wunderle, Marcus (BHP Billiton Petroleum) | Araujo, Ewerton (BHP Billiton Petroleum) | Alcalde, Rene (BHP Billiton Petroleum) | Yao, Calvin (BHP Billiton Petroleum) | Suhy, Fred (BHP Billiton Petroleum) | Jo, Thomas (BHP Billiton Petroleum) | Bases, Fleur (BHP Billiton Petroleum) | Sani, Abu M. (BHP Billiton Petroleum) | Ma, Yiwei (BHP Billiton Petroleum) | Bansal, Abhishek (BHP Billiton Petroleum) | Peterson, Eric (BHP Billiton Petroleum) | Goudge, Rohan (BHP Billiton Petroleum) | Awasthi, Ankur (BHP Billiton Petroleum) | Bhatia, Mukul (BHP Billiton Petroleum)
The Haynesville Shale remains a prolific gas resource amongst the Unconventional Plays in the US. The continued viability and the commercial success of the play are highly dependent on the optimization of field development plans through drilling, completions, and production improvements.
This paper presents an integrated solution that includes geologic, geophysical, and geomechanical properties. The workflow includes a Discrete Fracture Network (DFN), modeled hydraulic fractures, and well diagnostics data, to improve the understanding of the subsurface. The goal is to provide valuable input to optimize the development plan and completions strategy in the Haynesville Shale.
The development of the integration platform (3D geo-cellular model) involved detailed seismic interpretation based on a sequence stratigraphic framework, definition of stratigraphic-mechanical units, and incorporation of a robust petrophysical analysis set in a structurally controlled grid. The structural framework of the model was enhanced using over 100 carefully interpreted geo-steered horizontal wells to improve accuracy and grid calibration to the well paths. The natural fracture analysis included core description and fracture counts complemented by borehole image data, which coupled with a geomechanical stratigraphic characterization study, assisted in understanding the field wide fracture intensity distribution and orientation.
The hydraulic fracture conductivity and net pressure profiles, along hydraulic fracture planes, were developed using a planar geometry fracture simulator. The results served as input to the geomechanical model and as the basis for hydraulic fracture stage design setup in the dynamic model.
A 3D geomechanical model was constructed using the geologic model, based on the pore pressure and mechanical properties from calibrated 1D-geomechanical models. Computational geomechanical simulations allowed us to identify reactivated natural fractures, which produced synthetic-microseismic events, and the Critically Stressed Fracture Volumes (CSFV). These inputs were used in the subsequent identification of Stimulated Rock Volumes (SRV). Interpretations are supported by tracer data and other field observations that assisted in establishing inter-well connectivity.
The products from these processes will be incorporated into a reservoir simulation model. History matching of production data will be conducted for validation and refinement. History matched models will be used to identify and evaluate the impact of key drivers of optimization studies to various field development scenarios in order to enhance well completion and well spacing strategies in the development plan.
While the active Lower Cotton Valley horizontal play in north Louisiana is receiving press and industry attention, individual horizontal wells, which are often close together, have demonstrated widely varying production results. The column of stacked pay sands can present targeting and fracture planning challenges because of varying pay quality and stress conditions. Typically two, or even three, individual target intervals can be present at any location, and accurate formation evaluation is crucial in deciding which zones to pursue and what fracture completion strategies to employ. This paper describes a custom vertical well evaluation workflow to address these challenges as a particular case study.
An enhanced logging suite using neutron capture mineralogy, magnetic resonance imaging, oriented acoustic dipole imaging, and electrical borehole imaging was deployed to address specific reservoir quality and stress conditions present in the primary Middle and Lower Poole sand pay zones and the Gray sand interval, a deeper secondary pay. Accurate mineralogy was used to quantify effective porosity and any clay reactivity issues with completion fluids. Magnetic resonance was used to quantify both permeability and free gas in the pay analysis. Oriented dipole data were used to quantify anisotropic stress conditions for accurate fracture modeling. Finally, borehole imaging was employed to identify natural fractures and possible faults, structural dips, and primary stress orientation for optimized horizontal placement.
Using the additional logs within the workflow, a larger picture of fracture stimulated reservoir deliverability was developed. Individual target zones were quantified by cumulative permeability-height (kH), analysis, and similar effective closure stress. This was used with a three-dimensional (3D) fracture simulator to achieve maximum fracture height design to contact the greatest volume of kH. This methodology was performed on the case study well, resulting in an actual Gray sand vertical production test and a recommendation of a Middle Poole sand as the primary horizontal target. The case study well results are discussed in depth and compared to predicted results.
This evaluation workflow is unique because it predicts fracture stimulated flow performance for each zone before actual completion. It can be used to make vertical pipe set or horizontal landing decisions soon after the openhole logging is completed to optimize individual well performance following stimulation operations.
The interest in restimulating unconventional wells in recent years has been driven by multiple factors—the desire to arrest the steep decline curves of unconventional wells, the depressed prices for both oil and natural gas, and the optimization efforts to fully drain reservoir rock that might have been inefficiently stimulated during original completions. Numerous publications have documented that a restimulation treatment can either add to the estimated ultimate recovery (EUR) of a well or accelerate the recovery rate of that well's EUR. Efforts are now focused on making restimulation treatments more effective with more repeatable results.
Early diagnostic methods have shown that in some horizontal restimulation treatments, the majority of the fluid and proppant pumped are delivered only into the first 1,000 to 2,000 ft of the lateral. These diagnostic methods include microseismic monitoring, radioactive proppant tracer, and production logging. In June 2015, one Haynesville shale well was restimulated and evaluated using radioactive proppant tracer to provide insight into the stimulation coverage of the lateral. The restimulation design for the case history well focused on treating the entire lateral with the use of a biodegradable particulate diverter. This was accomplished by increasing the amount of material per diversion cycle and by increasing the number of cycles in the restimulation treatment. Additional consideration was given to delivering an optimized proppant amount per lateral foot, ideal cluster spacing, treatment fluid selection, and appropriate treatment rate.
The case history shows that 63 of the 70 clusters identified with the tracer log were stimulated during the restimulation treatment. Additionally, the clusters showing proppant were located throughout the entirety of the lateral. The size and composition of the restimulation design is analyzed with respect to treatment performance, and possible improvements are considered. The economic viability of a restimulation program should be weighed against the entire cost of a restimulation treatment, which includes wellbore preparation, wellbore integrity testing, cost of restimulation services, and other miscellaneous logistical challenges encountered before the treatment begins.
Knowledge of Biot poroelastic coefficient is crucial to geoscientists for a number of applications, including oil and gas exploration and production, and hydrogeology. This in turn requires estimation of bulk and grain modulus or compressibility. Although bulk modulus estimation is a standard laboratory method for shale, no effort was made till date to directly measure grain compressibility in the laboratory. This paper presents a laboratory study to fill this gap. The experimental program described here starts with validation of the technique using aluminum sample. Following this, one Berea sandstone and one shale sample was tested. Finally, using the measured data, Biot coefficient was estimated for shale. General agreement with published literature was observed. However, since none of the reported data was obtained through laboratory measurement, further measurements need be performed for shale and other reservoir rocks.
During deposition and diagenesis, cracks and pores are created in subsurface strata. These void spaces or porosity are in turn occupied with one or more fluid phases ranging from water to liquid or gaseous hydrocarbon depending on depositional/post-depositional environment. Intuitively, the mechanical behavior of subsurface strata filled with fully or partially saturated pore spaces differs from that of a rigid or non-porous rock. The extraction of hydrocarbon results into change in pore fluid pressure in subsurface strata. The processes of drilling and completion impact the existing in situ stress field. This is further complicated when intentional/unintentional production of hydrocarbon occurs as the resulting change in pore pressure once again affects the stress field. The effects of pore pressure change on the deformation around a borehole (Detournay and Cheng, 1988), hydraulic fracturing (Detournay et al., 1989) and slip along active faults (Rudnicki and Hsu, 1988) have been reported earlier. To fully understand this, the theory of effective stress was first proposed by Carl Terzaghi on one-dimensional consolidation of soil which was later extended to three-dimension by Biot (1941). Following this, Geertsma (1957) and Skempton (1961) separately defined the expression for effective stress for a fully saturated material, which was later mathematically derived by Nur and Byerlee (1971). In their work, effective stress is expressed as:
where Pe, Pt and Pp are effective, total and pore pressure, respectively, α is Biot coefficient and K and Ks are bulk and grain modulus. Biot coefficient was subsequently utilized in estimating insitu stress (Thiercelin and Plumb, 1994) as well as in wellbore stability analysis and hydraulic fracture design (Cheng et al, 1993). As revealed in Eq. (2), it requires estimation of both bulk and grain modulus. This in turn involves saturating the rock material with pore fluid which presents a challenge for fine-grained rock like shale. The complex pore structure and nanometer range pore diameter of shale makes the saturation a shale sample in the laboratory significantly longer, making the test protocol impractical. This paper explores an alternative laboratory technique which is simply a variant of the unjacketed compressibility test. The paper begins with a description of the experimental technique in detail. This is followed by presenting the results conducted using an aluminum cylinder, the purpose of which is entirely validation of the experimental technique. The presentation is concluded by reporting results on Berea sandstone and shale and estimating Biot's coefficient for those samples. The results presented here indicates usability of the technique in estimation of grain modulus and hence, Biot coefficient, for shale. The readers should note that as shown in Eq. (2), Biot coefficient is estimated using modulus instead of compressibility, it's reciprocal. Similarly, all laboratory measurements presented in this paper report a modulus value and one can estimate compressibility from them.
Six years ago, the Upper Jurassic Haynesville Shale play was largely unknown as an unconventional shale play. US government and oil company resource assessments for such unconventional plays vary significantly. Here we attempt to estimate resource potential using a full mass balance approach based on data from more than 1600 recently drilled wells, integrated into a 3D petroleum systems model.
Numerous iterations were conducted to simulate heat flow in the study area. The simulated heat flow calibrated to vitrinite reflectance data from 26 wells suggests that a slight increase in heat flow may have occurred with every uplift event over the Sabine Uplift area.
Laboratory analysis of a number of Haynesville Shale samples taken from six wells reported an original total organic carbon (TOC) content, which is on average 3% for all samples. Additional Rock-Eval analysis revealed that all of the samples taken from the wells are overmature. Adsorption isotherms were determined on one representative sample and implemented in the modelling approach to calculate adsorbed gas volumes.
After simulation, the accumulation calculations in the Haynesville Shale revealed a total amount of 2056tcf of adsorbed gas (79.15% Methane) and 1511tcf of free gas (87.12% Methane). These numbers seem to be very high, but considering a recovery factor of 5 or 10% the combined producibility of gas based on our model will be equal to 178 or 357tcf respectively. Most of the primary production of gas occurred during the Aptian-Albian, and secondary cracking produced most of the free gas during the Early-Eocene.
The model also shows wide variability in pore pressure and the generation of abnormal pressures. This variation in pore pressure occurs in the Haynesville Shale and results from a combined effect derived from the overlying Cotton Valley/Bossier Formation and the underlying Smackover Formation. As a final observation, the critical moment of the Haynesville Shale petroleum systems has been dated to be at the Turonian and Early-Eocene. At this point all petroleum system elements and process have been satisfied for the conventional and the nonconventional play respectively.
Santacruz, Carlos (BHP Billiton Petroleum) | Esquivel, Raul (BHP Billiton Petroleum) | Smith, Jordan (BHP Billiton Petroleum) | Walker, Rick F. (BHP Billiton Petroleum) | Bayer, Sebastian (BHP Billiton Petroleum) | Soto, Thomas (BHP Billiton Petroleum) | Wunderle, Marcus (BHP Billiton Petroleum) | Bansal, Abhishek (BHP Billiton Petroleum) | Goudge, Rohan (BHP Billiton Petroleum)
The key concept involved constraining non-unique history matches through utilizing Rate Transient Analysis (RTA) characterization of the reservoir and completion designs with early well performance to guide subsequent modeling of the reservoir. The three step approach consisted of 1) identifying observed and anticipated flow regimes through Rate Transient Analysis diagnostics, 2) incorporating these into an analytical model to match production history, and 3) generating production forecasts with the history matched analytical model, with verification by numerical modeling on representative wells. More than 325 wells with production and pressure data were evaluated. In each well, different flow regimes were identified with rate transient analysis diagnostic plots, capturing the product of the cross sectional area of flow and square root of permeability (Ak), time to the end of linear flow (Telf), and the Area of Stimulated Rock Volume (SRV). Petrophysical and geomechanical properties for the model were interpolated for each producer, sourced from a regional 3D geologic model which integrated more than 130 pilot wells with petrophysical analysis and 55 wells with core analysis. As a result of the integration of geological modeling, reservoir surveillance and analytical simulation efforts a new forecasting methodology was generated and confirmed by correlations between well performance, Estimated Ultimate Recovery (EUR) and Ak. Furthermore, an alternative fracture efficiency approach was derived from the Telf and depth of investigation from the linear transient equation. The results of this calculation suggest that previous completion designs generated few, but long fractures, consistent with evidence of frac hits in the field.