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New Mexico’s state treasurer is calling on state environmental regulators to close loopholes in proposed rules aimed at reducing emissions of methane and other pollutants from the oil and natural gas industry. State Treasurer Tim Eichenberg confirmed that he has joined with a long list of socially responsible investment groups that are citing gaps in proposed regulations from the Environment Department and the state Energy, Minerals, and Natural Resources Department. They outlined their position in a letter sent to Democratic Gov. Michelle Lujan Grisham. Lujan Grisham’s administration has said New Mexico stands to have some of the most expansive rules for addressing methane and other emissions from the oil and gas industry after many meetings with industry experts and environmentalists. The draft rules released by the environment department target oil and natural gas equipment that emit volatile organic compounds and nitrogen oxides.
The first rendering of what is to be the world’s largest direct-air-capture-plant in the Permian Basin. The facility is expected to capture up to 1 million metric tons of CO2 annually for enhanced oil recovery operations in Texas. Occidental Petroleum (Oxy) announced this week that it is joining the race to net-zero carbon emissions. The first step will be to eliminate or offset emissions from its own operations by 2040. The more ambitious leap will require the Houston-based company to do the same for all the oil and gas products it sells by 2050.
As the shale development activity in the Permian continues to be strong and oil prices recover, increasing numbers of infill child wells are being drilled as operators want to improve recovery from each section and continue to meet their production targets. However, production data suggests that both parent and child wells suffer from production losses if they are located too close to one another.
The cube model concept, which is also referred to as supersize fracturing, was first introduced about two years ago and has been piloted in the Permian Basin. In a cube model, multiple wells, usually more than 30 horizontal wells with five to six wells in each different horizontal layer, are drilled and completed in the same section. Operators produce those wells simultaneously with the objective of mitigating the parent-child effect of unconventional reservoirs.
Nevertheless, with all wells producing at the same time and competing for production from the first day, will this benefit ultimate recovery? This question was investigated through comprehensive fracture and reservoir modeling and simulation. A reservoir dataset for the Spraberry Formation in the Permian Basin was used to build a hydraulic fracture and reservoir simulation model.
Different field development strategies were studied. Models representing a traditional parent-child scenario with five parent wells completed and produced one year before four infill child wells and a traditional parent-child scenario with five parent wells completed and produced five years before four infill child wells are compared. In these cases, a geomechanical finite-element model (FEM) was used to quantify the changes to the magnitude and azimuth of the in situ stresses from the various reservoir depletion scenarios. Next, a cube model with nine horizontal wells completed and produced simultaneously was analyzed. These three scenarios were expanded to include 19 horizontal wells with the same methodology.
This study aims to help operators in the Permian Basin, as well as in other unconventional reservoirs to understand how different field development strategies affect ultimate hydrocarbon recovery and net present value.
For many unconventional reservoirs, the initial oil saturation is extremely low (around 30 %). In such circumstances, it is necessary to use alternative geological and hydrodynamic simulators to forecast production levels. A novel adaptive modeling approach based on cascades of fuzzy logic matrices was proposed and implemented for a mature carbonate oil reservoir in the Permian basin of Texas where next generation waterflooding was considered to revive development process and increase oil recovery.
The proposed approach is a variant of machine learning to solve the classical analysis and synthesis problem. At the analysis stage, the input and target parameters are normalized in order to equalize their significance. For each pair of input parameters, a fuzzy-logic matrix is formed and populated with actual values of the target parameter. The set of matrices forms a cascade in which every component is characterized by its own membership function. At the synthesis stage, forecasted results of the target parameter are calculated taking into account all membership functions and correspond to the maximum values of their superposition.
By means of the proposed approach, geological and hydrodynamic models of the unconventional reservoir were successfully created, which made it possible to estimate the distribution of its initial and remaining oil reserves for all reservoir formations. The options for further reservoir development were also considered including the reactivation of non-operating wells, drilling new wells, and initiation of waterflooding. The obtained results confirmed that waterflooding was able to enhance the cumulative oil production of the reservoir compared with the base case without waterflooding, and its role became more significant as the number of operating production wells increased. The calculated results also showed that the proposed approach was quite sensitive to the changes of input parameters, for example, to the number of production and injection wells. The cumulative oil production varied several times depending on the considered option. The calculated results justified the ability of the proposed approach to forecast the development results and to choose the proper strategy for the reservoir reviving. A distinctive feature of the proposed approach was its ability to adapt to any of geological and field conditions, such as the extremely low initial oil saturation that most reservoir simulators do not take into consideration.
Several oil and gas industry applications of artificial intelligence have been presented in the last decade. Machine learning techniques take center stage in most presentations. Prior to performing the actual modeling in data analytic project, the first three steps in the data analytic lifecycle involve planning, data preparation and model planning. Data visualization is an important aspect in the model planning phase as it aids in selecting variables that are important for modeling and in deciding the appropriate choice of ST model to use. Hence, it is important to invest time and resource to carry out this aspect of the project in order to delineate patterns in the dataset. Researches conducted in this area in the oil and gas industry have not maximized the power of visualizations, particularly when it comes to spatio-temporal data analysis.
In this paper, we present applications of spatio-temporal exploratory data analysis for oil and gas datasets using ST-plots, applied on dataset from four unconventional formations in the US: Bakken, Marcellus, Eagleford and Wolfcamp and Bone Spring formations in the Delaware Basin. Several plots are presented, including space-time plots, animations, Hovmöller diagrams,temporal histograms, and boxplots – capturing variations in oil and gas production across space and time.
In the first plot, we show variation in yearly oil production across space with different panels representing time domains. This plot shows the development of an area with few wells in the initial stages and additional wells in later stages. Colors can be added to capture the magnitude of the yearly oil/gas production, normalized with days produced. Areas of the field that contribute to higher production becomes apparent. Animations can be used to present this data monthly as is typical in production data reported to state agencies. For unconventional formations, further normalization can be done with the number of completion stages or lateral length. Hovmöller diagrams are good alternatives with space on the x-axis and time on the y-axis. This plot enables us capture spatial (in)dependence of the dependent variable and can suggest the use of space as a covariate in the final model. Another plot that could be useful is the temporal histogram, in which the third dimension is time. This plot could be useful in deciphering a suitable model for the data and clearly show if the distribution or average changes over time. We highlight how these plots aid in variable selection for spatio-temporal modeling of production data.
These plots are not the typical plots used in presenting oil and gas data and hence the application is new in this regard, in addition to the temporal histogram and boxplots which are new additions.
Electrical Submersible Pumps (ESPs) are commonly applied to producing wells in unconventional reservoirs. Typically, the operator places the ESP in the vertical section to minimize installation risks; however, some operators have reported installing ESPs in the lateral section to improve operation and production. This paper will present a study of the interaction between reservoir inflow, wellbore geometry, and ESP operation using a commercial dynamic multiphase flow simulator (OLGA). The study will further quantify the benefits and disadvantages of deploying the ESP in the vertical and lateral sections of a horizontal well. The investigation uses operations data from a Permian basin well, with an ESP operating in the vertical section of a horizontal well. The dynamic simulation model was built and tuned to match the field data with two different production stages: early and late production. Hypothetical cases with the ESP located in the lateral section and with different well geometries (toe-up and toe-down) are also investigated. For the performance evaluation of different ESP deployment positions, the following indicators were considered: (a) production flow rate, (b) likelihood of pressure surging occurrence, and (c) flow pattern and gas volume fraction reaching the ESP system. Finally, the study provides guidelines on the ESP deployment location for improved operation and production.
We present a review of new gas lift technologies designed to deliver increased production rates when compared to conventional gas lift systems and demonstrate the applicability of these systems in unconventional development wells in the Permian Basin.
We focus on results from wells employing electrically operated downhole injection technologies that provide a deeper point of injection and conserve surface injection pressure, reducing flowing bottom hole pressure. We present wells that represent a range of the inflow performance spectrum in the Permian Basin. These wells were completed with remotely operable injection stations to understand the impact of a variety of flowing conditions.
Several Gas Lift indicators are used for efficiency evaluation criteria: Depth of injection, multi-pointing elimination or reduction, and properly-sizing injection port to enable gas injection at critical flow. Downhole and surface conditions were continuously and remotely monitored, and included pressure and temperature sensors at each station, both inside and outside of tubing.
We present results that: enabled tuning of annulus pressure calculations; provided reliable gas lift modelling and optimization when compared conventionally equipped gas lift wells; demonstrated the benefits of preserving Gas Lift pressure for single point of injection as deep as possible. These results delivered performance increase, reduced uncertainty in diagnostics and well performance analysis and enhanced completion designs that included the remote operated valves. In all situations the depth of injection was moved further down the well, eliminating multipoint injection observed in conventional gas lift equipment.
Currently, there are several electrically operated gas lift valves available on the market with similar capabilities but vary in design and implementation. Ongoing evaluation of these technologies enable maturation of this technology and creates the opportunity to combine it with integrated production optimization and autonomous operations in the future.
Salt water, produced water, waste water, oilfield brine—regardless of what you call it, large volumes have been coproduced with oil in the US for decades. But the volumes have surged in the past few years and doubled since 2009, along with widespread seismicity in some regions, most notably Oklahoma and, more recently, the Permian Basin. The increase in produced water and concerns about its effects have recently spawned a new business sector known as “the water midstream.” An estimated $9 billion to $11 billion of private capital has been committed to the oilfield water midstream business to date, and a further $16 billion is projected to be required. The value proposition for this business is optimizing the treatment and disposal of produced water, currently at water/oil ratios of approximately 4:1 for unconventional wells and 13:1 for conventional, at scale.
Parker, Martyn (Pruitt Tool & Supply Co.) | Seale, Marvin (Red Willow Production Company) | Nauduri, Sagar (Pruitt Tool & Supply Co.) | Abbey, James (Red Willow Production Company) | Seidel, Frank (Seidel Technologies, LLC) | Okeke, Ernest (Pruitt Tool & Supply Co.)
Horizontal drilling in the Fruitland Formation, a Coalbed Methane (CBM) play located in the San Juan Basin (SJB), found across the states of Colorado and New Mexico can present a number of drilling and production challenges. Examples of these challenges include wellbore instability, severe fluid losses, high mud costs, formation damage, and post-well production issues.
Clear fluid brine systems such as Calcium Chloride (CaCl2) and Calcium Bromide (CaBr2) are usually preferred because of their compatibility with coals and their ability to minimize formation damage. However, these brines can instigate fluid losses, cause fluid handling issues, and create long-term production challenges. Coal instability in the horizontal play has historically led to events such as wellbore collapse, stuck pipe, lost Bottomhole Assemblies (BHAs), and challenges such as getting the pipe out of the hole at Total Depth (TD) and subsequently running completions. Ultimately, these problems led to sidetracks, incurring additional costs, time, and resources.
In May 2019, the Constant Bottomhole Pressure (CBHP) technique of Managed Pressure Drilling (MPD) was introduced to mitigate these challenges. Two wells with eight laterals and combined horizontal footage of ±46,000 ft were drilled using CBHP, maintaining 11.4 ±0.1 pound per gallon (ppg) Equivalent Circulating Density (ECD) and Equivalent Static Density (ESD) in the lateral at ±2800 ft True Vertical Depth (TVD). With a focus on safety and training, the mud weight was staged down from 10.8 ppg on the first lateral to 9.8 ppg on the second. The final six laterals were drilled with 8.6 ±0.2 ppg produced water. This paper will detail the planning, training and staged implementation of CBHP MPD with produced water. It will briefly discuss improvement in wellbore stability, cost reduction for drilling laterals, and enhanced production after switching to produced water.
Solaris Water Midstream has begun operations at its newest large-scale water-reuse complex in New Mexico, the Eddy State Complex. The complex can supply 300,000 B/D of recycled produced water for operators in the northern Delaware Basin. Th complex adds to the company’s ongoing recycling operations at its Lobo Reuse Complex in Eddy County and the Bronco Reuse Complex in Lea County. Two additional water-recycling centers are expected to be completed by December. When all five water-reuse complexes are operating, Solaris Water will have the capacity to recycle more than 900,000 B/D of produced water, with over 3 million bbl of adjacent storage capacity.