Not enough data to create a plot.
Try a different view from the menu above.
Expanding its holdings further in the Delaware Basin, WaterBridge Holdings closed a transaction with Colgate Energy to acquire the produced water infrastructure associated with Colgate's purchase of Occidental acreage in June. The companies entered into a 15-year produced water management agreement for all of Colgate's operated acreage within Reeves and Ward counties, Texas. The acquired assets include 10 water-handling facilities and associated water midstream infrastructure with aggregate handling capacity of approximately 100,000 B/D and approximately 50 miles of produced water pipelines. WaterBridge will manage the produced water infrastructure and integrate these assets into its broader southern Delaware operations. WaterBridge and Colgate have consolidated existing produced water management contracts into a new produced water management services agreement in which Colgate has dedicated all the operated acreage recently acquired from Occidental and the legacy Colgate and Luxe Energy acreage previously dedicated to WaterBridge.
Unconventional completions engineering is often a game of inches. One where winning is increasingly defined by gaining incremental control over capital, geologic uncertainty, and preconceptions about how to do it right. This spirit of continuous improvement remained a chief undercurrent of this year's Unconventional Resources Technology Conference (URTeC) in Houston. Chevron and Occidental Petroleum (Oxy) were among the largest Permian Basin operators at the conference to reveal how their completions philosophies evolved amidst the onset of a low-capital environment. Chevron reports that it's saving around 8% on new well pads while also adopting new proppant schedules that have reduced its reliance on chemical additives.
NexTier Oilfield Solutions is emerging into a role as consolidator in the fragmented US pressure pumping market by acquiring Alamo Pressure Pumping in a cash-and-stock transaction worth $268 million. The deal, which is expected to be completed by 31 August, brings together two leading providers of low-carbon well completion solutions in the Permian Basin. NexTier itself was born from the merger of C&J Energy Services and Keane Group in late 2019. The Alamo fleet comprises nine, primarily CAT Tier IV, young hydraulic fracturing units. The acquired assets comprise 460,000 horsepower, around 92% of which is Tier IV DGB (dynamic gas blending) capable.
Oil and gas executives across the North American shale sector are continuing to come to the table and negotiate a steady stream of deals to consolidate portfolios. During the second quarter, the deal making amounted to more than $33 billion in mergers and acquisitions, according to data from Enverus. The energy-focused analytics firm said last month in its quarterly review the combined figure represents more than 40 deals, with seven of them topping $1 billion each. The third quarter has so far not seen any announced transactions surpass the $1-billion mark. Instead, most deals struck in July were between mid-sized and small US-based operators.
Occidental Petroleum (Oxy) said this week it has agreed to sell almost 25,000 net acres in the Permian Basin of Texas to Colgate Energy Partners III for nearly $508 million. Average output of the properties amounts to 10,000 BOE/D from about 360 wells in the southern Delaware Basin, Houston-based Oxy reported in its announcement. The sale, expected to close in the third quarter, will boost Midland-based Colgate's holdings in the Permian to about 83,000 acres with an estimated production of 55,000. Colgate said it plans to run up to six drilling rigs by year's end and boost average production to 75,000 BOE/D by 2022. Proceeds from the sale will be used to pay down Oxy's debt that was around $35.4 billion in March, down slightly from the $36.03-billion debt reported last June.
Free data from the first Permian Hydraulic Fracturing Test Site is available online and reports from the second test site will be available this summer. Those reports offer a unique look at fracturing in the Midland and Delaware Basins, using nearly every diagnostic test an engineer can think of and analysis by technology leaders including Occidental and Shell among the partners. Because the US government shares the cost with industry partners, the data are made publicly available after a period during which the companies that pay half the cost have exclusive access to it. The data posted draw on work begun more than 5 years ago. It is available on the National Energy Technology Laboratory's EDX data sharing site (details below). The files offer processed data from testing done at an 11-well pad in the Midland Basin dating back to 2015, said Gary Covatch, a petroleum engineer at the US Department of Energy.
Abstract Drilling challenging wells requires a combination of drilling analytics and comprehensive simulation to prevent poor drilling performance and avoid drilling issues for the upcoming drilling campaign. This work focuses on the capabilities of a drilling simulator that can simulate the directional drilling process with the use of actual field data for the training of students and professionals. This paper presents the results of simulating both rotating and sliding modes and successfully matching the rate of penetration and the trajectory of an S-type well. Monitored drilling data from the well were used to simulate the drilling process. These included weight on bit, revolutions per minute, flow rate, bit type, inclination and drilling fluid properties. The well was an S-type well with maximum inclination of 16 degrees. There were continuous variations from rotating to sliding mode, and the challenge was approached by classifying drilling data into intervals of 20 feet to obtain an appropriate resolution and efficient simulation. The simulator requires formation strength, pore and fracture pressures, and details of well lithology, thus simulating the actual drilling environment. The uniaxial compressive strength of the rock layer is calculated from p–wave velocity data from an offset field. Rock drillability is finally estimated as a function of the rock properties of the drilled layer, bit type and the values of the drilling parameters. It is then converted to rate of penetration and matched to actual data. Changes in the drilling parameters were followed as per the field data. The simulator reproduces the drilling process in real-time and allows the driller to make instantaneous changes to all drilling parameters. The simulator provides the rate of penetration, torque, standpipe pressure, and trajectory as output. This enables the user to have on-the-fly interference with the drilling process and allows him/her to modify any of the important drilling parameters. Thus, the user can determine the effect of such changes on the effectiveness of drilling, which can lead to effective drilling optimization. Certain intervals were investigated independently to give a more detailed analysis of the simulation outcome. Additional drilling data such as hook load and standpipe pressure were analyzed to determine and evaluate the drilling performance of a particular interval and to consider them in the optimization process. The resulting rate of penetration and well trajectory simulation results show an excellent match with field data. The simulation illustrates the continuous change between rotating and sliding mode as well as the accurate synchronous matching of the rate of penetration and trajectory. The results prove that the simulator is an excellent tool for students and professionals to simulate the drilling process prior to actual drilling of the next inclined well.
Abstract Openhole oil sampling in the tight Middle Cretaceous reservoirs of Alaska can be challenging due to the proximity of the reservoir pressure to the fluid’s saturation pressure. Existing focused probe technologies commonly used in other conditions have limited application in these conditions because their small flow area means slow pumping rates, high drawdowns, and nonrepresentative fluid samples. Nonfocused inlets, such as 3D radial probes and straddle packers, are mostly used to sample in these reservoirs, but deep invasion and slow pumping rates mean using these alternatives leads to long station times. A new wireline formation testing platform has been field tested in three wells since 2018. The objectives included the evaluation of the platform’s abilities to pump at controlled speeds to keep flowing pressures always above the fluid’s expected saturation pressures. A new inlet was tested for focused sampling and higher flow rates with the intention of cutting operating time and improving sample quality. Also, increased sample container capacity enabled the collection of required sample volumes in fewer bottles, which resulted in a shorter and lighter sampling string configuration. A legacy pressure tool was added to the bottom of the new platform for pressure testing benchmarking. During the operation, the tool was positioned at target depth, and an automated routine inflated the inlet assembly to contact the formation. This automation cycle enables the tool to be ready for pumping in less than 15 minutes. In contrast, technologies used in previous operations required 30 to 45 minutes setup time before fluid cleanup could commence. Fluids were then flowed through the tool’s sample and guard lines with a sequence of commingling and focused pumping periods using two simultaneous pumps while assessing fluid quality with a downhole fluid analyzer. Strict control of the 1-cm/s selected rate for both pumps provided fast cleanup in focused mode with less than 100-psi drawdown. This has never been achieved before in these reservoirs. First hydrocarbon breakthrough was observed less than an hour into the pumping period. Previous operations reported 4 hours or more for first hydrocarbon breakthrough. Three stations were performed, and 10 single-phase samples were collected in as many bottles. Thin-bedded interval testing was possible given the ability of the new platform to collect samples with either the sample or guard lines. Total operating time to complete the program was 30 hours. Comparison with data from similar operations in previous campaigns shows a decrease of 50% in operating time, faster rig- up and rig-down, and decreased cable tension. These latter two aspects add to operational efficiency and mitigation of risks. This case study summarizes several pioneering aspects of the new generation of wireline formation testing platforms. It was the first time a combination of the new and legacy technology was deployed and the first time that high-volume multiphase sample bottles were used during a field test. It was also one of the first applications of this new technology in North America.
Johnson, Andrew C. (Schlumberger) | Miles, Jeffrey (Schlumberger) | Mosse, Laurent (Schlumberger) | Laronga, Robert (Schlumberger) | Lujan, Violeta (Schlumberger) | Aryal, Niranjan (Schlumberger) | Nwosu, Dozie (Schlumberger)
Abstract Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
Nicholson, A. Kirby (Pressure Diagnostics Ltd.) | Bachman, Robert C. (Pressure Diagnostics Ltd.) | Scherz, R. Yvonne (Endeavor Energy Resources) | Hawkes, Robert V. (Cordax Evaluation Technologies Inc.)
Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1: Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.