Fracture Gradient Research Articles

Numerical investigations on the performance of sc-CO2 sequestration in heterogeneous deep saline aquifers under non-isothermal conditions

CO2 sequestration in geological formations is an efficient step towards mitigating climate change by reducing global warming. The CO2 emitted from natural sources and anthropogenic activities is injected into geological formations. The flow and transport of CO2 during sequestration operations require in-depth knowledge of the effects of the type of geological formation. The present work analyses the CO2 migration and storage in a heterogeneous deep saline aquifer with variable porosity and evolving permeability under non-isothermal flow conditions while upscaling the capillary pressure using the Leverett J-function. The developed numerical model is history-matched with CO2 gas saturation profiles reported using analytical and numerical approaches. The novelty of the present work lies in its ability to capture fine-scale heterogeneities in the aquifer, which is modelled through variation in the porosity (ϕ) distribution and the permeability (k). The thermal-hydraulic numerical analysis projected a pronounced effect of the degree of heterogeneity arising from the variation in porosity and permeability on pressure buildup along the top of the formation decreasing from a maximum of about 6.41 MPa at the injection well to about 0.933 MPa at 1200 m and affecting gas characteristics and transmission. The thermal front could only propagate to a maximum extent of about 142 m from the injection well in aquifers, while gas plume lengths migrated to a maximum plume length of about 1010 m. The permeability and porosity of the aquifer are critically observed to vary during the sequestration by a ratio (k/k0) of about 1.07 to 1.01 and a percentage of about 0.791 % – 3.136 % in the low permeable conditions. Maximum effective storage of CO2 by a factor of 0.95 observed in low-permeable heterogeneous aquifers with normally distributed porosity affirms maintenance of optimum gas injection rates below the fracture gradient in these formations to sequester the CO2 economically.

BRIEF UNDERSTANDING OF CHARACTERISTICS DEPLETED RESERVOIR (INTERVAL-I) USING PORE PRESSURE AND FRACTURE GRADIENT ANALYSIS IN "X" FIELD, SANGA-SANGA AXIS, KUTAI BASIN

Field X, as this study area's focus, boasts over 200 wells proven to be hydrocarbon producers. Two pore pressure regimes exist: normal hydrostatic and overpressure. The primary hydrocarbon reservoir in the Balikpapan Formation within the Sanga- sanga axis at Field X consists of sandstone. Drilling disturbances, particularly in the lower intervals of this reservoir, often occur due to overpressure. The main challenge encountered in this reservoir is mud losses. The objective of this study is to develop the Pore Pressure and Fracture Gradient characteristics and its relation to the geological environment. Furthermore, the distribution of Sand (Interval-I) is determined, which is the primary cause of losses due to production. Besides that, the parameters used to create optimal fracture gradient is also defined. Thirteen wells in this field were examined to identify the controlling factors of pore pressure. This study integrates wireline logging, velocity, mud logs, pressure tests, drilling parameters and event which are subsequently processed for determining shale points, Normal Compaction Trend (NCT), calculating overburden gradient, and estimating pore pressure using the Eaton method. From the analysis result, the distribution of overpressure and the generating mechanism of overpressure are determined. This study also carried out analysis to determine overpressure and depleted Sandstone (Interval-I) distribution. Subsequently, facies and depositional environtment analysis are conducted, followed by modelling Sandstone (Interval-I) and determining Sandstone’s poisson ratio from loss data and shale’s from leak of test data for fracture gradient estimation. Overpressure is found in Interval-I with magnitude of 4000-4700 psi, which corresponds to delta plain to delta front depositional environment. Top of overpressure is observed shallower in the southern than northern due to geological structure conditions. The generating mechanism of overpressure is caused by loading and hydrocarbon generation. The experienced loss in overpressure zone, caused by reservoir production from the initial pressure of 4475 psi and has depleted to 373 psi. From the sandstone distribution model, the loss sandstones are a connected fluvial channel in southern ward. It is also observed several unconnected channel sandstones that did not experience loss. Poisson ratio parameter for sandstone is 0.35, which is calibrated from the loss event with minimum fracture gradient in Interval-I is approximately 4772 psi. It is expected that the understanding of pore pressure and Sandstone (Interval-I) distribution could be used to increase the success ratio for optimal drilling planning, including to choose effective casing design, mud weight, and appropriate total depth.

A Comprehensive Geomechanical Study to Understand Drilling Challenges in the Eridu Oil Field, Southern of Iraq

In recent years, the Eridu oil field has emerged as a key player in the petroleum industry in southern Iraq as it is the biggest Iraqi oil discovery in 20 years. Extending along a vast area of 5806 km2, the field has commercial oil reserves in formations such as Mishrif, Nahr Umr, Zubair, and Yamama. However, drilling operations in this field have faced significant challenges, including delays and suspensions caused by wellbore instability. One of the main obstacles encountered during drilling operations in the Eridu oil field is the occurrence of partial losses in weak vugs dolomite formations, as well as issues related to sever borehole instabilities such as drilling in tight holes, caving, and breakout due to shear failure in the borehole wall. To address these challenges, a 1 D Geomechanical model (1-D MEM) was constructed using data from vertical wells to better understand the underlying causes of drilling problems. The findings of the 1-D MEM, particularly in relation to mechanical rock properties, rock Elasticity factors, pore pressure, and fracture gradient complex formations like Tanuma and Mishrif, were instrumented in planning drilling operations for inclined and highly deviated wells. By utilizing open hole well logging data and calibrating the model with various resources of data including drilling observations, core mechanical analyses, and pore pressure measurements, a more accurate assessment of wellbore instabilities was achieved. The analysis revealed that many of the wellbore instabilities, such as pack-off, breakout, and stuck pipe, were attributed to the insufficient mud weight that failed to support the rock in the borehole wall. To avoid these issues, it was determined that a safe mud weight range of 11-12.5 ppg is necessary to prevent wellbore instability in shale formations. The study also highlighted the importance of using proper mud weight to prevent shear failure and other drilling complications. The findings of this study provide insights that can be utilized as a cost-effective tool for planning directional and horizontal drilling operations in the Eridu oil field. The accuracy of the failure criteria and geomechanical model is significantly superior and aligns with the analysis of breakouts observed in the caliper and image logs.

First Successful Wireline Stress Testing in a Gas Hydrate Reservoir in the Hyuganada Sea, Japan

This study presents a stress testing operation conducted using a wireline formation tester in a newly discovered gas hydrate prospect located offshore in Japan. The campaign, which spanned from December 2021 to January 2022, involved drilling a well using logging-while-drilling technology. Subsequently, wireline formation testing and stress testing were successfully conducted at three different depths within a gas hydrate-concentrated zone. The testing was accomplished in a single riserless descent, with the primary goal of obtaining crucial data such as mobility, formation pressure, and fracture gradient for one of the prospects. This operation marked the first stress testing job performed with dual packers in an open water and deepwater environment specifically for gas hydrate reservoirs. The study also provides a comprehensive interpretation of the data gathered during the operation. Moreover, it evaluates various properties such as formation mobility, formation pressure, initial breakdown pressure, closure pressure, fracture propagation pressure, and instantaneous shut-in pressure.

Variation of vertical stress in the McArthur and Beetaloo basins

The McArthur and Beetaloo basins have been the focus of unconventional hydrocarbon exploration, specifically targeting shale gas and tight gas resources. Vertical stress (SV), which is one of the three principal stresses, is a critical parameter in geomechanical analysis of sedimentary basins and has implications in fracture gradient calculation, pore pressure prediction, assessing the present-day stress regime, and hydraulic fracturing design. In addition, variations in vertical stresses can yield additional insights into the tectonic history of an area. In this study, we examine the variability of vertical stress magnitude and vertical stress gradients by employing a systematic analysis of density log and check-shot velocity data obtained from 31 wells located within the McArthur and Beetaloo basins. Our analysis revealed that vertical stress gradients range from 23 to 27 MPa/km (equivalent to ~1.0–1.2 psi/ft), with an average gradient of 25 MPa/km ± 1.0 (1.1 psi/ft). This variability in SV gradients underscores the inadequacy of the commonly assumed 1.0 psi/ft approximation for geomechanical analyses within these basins. The origins of such diverse SV gradients can be attributed to several factors; however, the likely cause of the SV gradient within this region is the presence, thickness, and depth of the shallow high-density volcanic rocks and a complex history of uplift and erosion.

Study Explores Challenges, Potential of Superlaterals in the Vaca Muerta

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3968851, “Breaking the 5-km Barrier: Superlaterals Delivery Challenges—Are They Feasible in Vaca Muerta?” by Julio Palacio, SPE, Walid Ben Ismail, and Richard Walker, K&M Technology Group, et al. The paper has not been peer reviewed. _ Driven by increased production rewards, multiple operators in the United States have been improving their unconventional wells by increasing lateral length. Several “superlaterals” with lengths greater than 23,000 ft have been drilled successfully in several US basins. The complete paper describes the technical challenges faced in drilling and running casing in superlaterals and the difficulties in implementing them in the Vaca Muerta unconventional play. Introduction In 2012–2015, many operators began to drill longer laterals. Because production did not appear to decline with increasing lateral length, one operator drilled 11 superlaterals in 2017 in the Utica shale, reporting critical cost reductions and a greater recovery per foot. This operator used the term “superlateral” to describe a lateral length of 15,000 ft or greater. At the time of writing, several wells have exceeded a lateral length of 23,000 ft and can be categorized as extreme-reach wells. Typically, any well in the extended-reach region requires a large focus on operational practices and may require important design changes and special technologies or techniques to achieve its goals. Geomechanics Challenges The Vaca Muerta/Quintuco system is a late Jurassic to early Cretaceous play with a depth of more than 8,200 ft true vertical depth (TVD). Pore pressure in Quintuco can vary between 14.2 and 18.8 lbm/gal. Fractures connecting different zones and depths lead to discontinuity and important uncertainties in both pore pressure and fracture gradient. Historically, Quintuco was isolated by running casing before entering the Vaca Muerta. However, several operators drill Quintuco and Vaca Muerta in the same section to reduce the well cost. Using this approach, Quintuco pressure uncertainties effectively limit the maximum lateral length. To reduce this uncertainty effect, managed pressure drilling (MPD) has been used successfully in current laterals. Bedding-plane instability limited early development of unconventional horizontal wells. Its effect is not commonly perceived while drilling but can affect bit trips and casing runs catastrophically. Higher mud weight (MW) has helped mitigate, but not eliminate, bedding-plane instability in unconventional plays around the world. However, higher MW can constrain more than the MW window requirements in the Quintuco/Vaca Muerta system. As the lateral progresses in length, the annular pressure increases proportionally. Given that the TVD remains almost constant in horizontal wells, the equivalent circulating density (ECD) change will increase proportionally to the lateral length. Because of this ECD behavior in horizontal wells, MPD cannot be used to manage the wellbore-stability (WBS) margin reduction in longer laterals or to eliminate pressure fluctuations during connections. In very long laterals, the only way to better manage the WBS margin, bedding-planes issue, and induced wellbore instability can be a well-design change to increase the annular clearance after performing extensive modeling. MPD and surface-parameter control can marginally help to control the problem.

Predicting Onset of Sand Production in Oil Wells using Machine Learning

Sand production in oil wells is a significant challenge that negatively impacts productivity and compromise equipment integrity. This study explores the application of Optimized Support Vector Machine (SVM) binary classification algorithm to predict the onset of sand production in oil wells. A dataset from 63 oil wells was utilized, and class labels were determined based on the bulk and shear modulus product. The model development incorporated geological and mechanical parameters that could influence sand detachment such as: Young’s modulus, Poisson’s ratio, minimum and maximum horizontal stresses, overburden pressure, pore pressure, depth, fracture gradient, and formation strength. Instances above the threshold of 8E+11 were classified as indicative of no sand production, while those below were considered potential sand production scenarios. The SVM model demonstrated remarkable accuracy in predicting sand production onset, trained and tested rigorously with field data. The model's accuracy was evaluated using statistical parameters, such as: accuracy (ACC), sensitivity (SE), specificity (SP), and Matthew's Correlation Coefficient (MCC). From the results, the model achieved a score of 1 across all parameters, indicating high reliability and accuracy in sand production prediction. The practical implications of this model are significant, offering assistance to completion engineers in making proactive decisions regarding sand control strategies. Furthermore, the integration of this model into oil and gas industry processes can optimize operational efficiency by foreseeing potential sand production events, hence, preventing production impairment and ensuring loss prevention.

CO2 Injectivity Test Proves Concept of CCUS Field Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.

Crucial Development Technologies for Volcanic Hydrocarbon Reservoirs: Lessons Learned from Asian Operations

Oil and gas reservoirs in volcanic rocks are a particular type of unconventional reservoir and present unique challenges for exploration and production engineers. To help the oil industry understand volcanic reservoirs and solutions to complex development problems, we reviewed their key engineering technologies as well as their geological characteristics. The distinctive geological characteristics of volcanic hydrocarbon reservoirs are strong heterogeneity, low porosity and permeability, complex fracture systems, etc. The volcanic reservoir rock types in order of hydrocarbon abundance are basalt (38.5%), andesite (15.9%), volcaniclastic (12.1%), and rhyolite (11.5%). The porosity ranges from 0.1 to 70%, and permeability ranges from 0.0007 to 762 md. In some commercially developed volcanic reservoirs of China, the average porosity is 7.7–13%; the average permeability is 0.41–3.4 md. Engineers have applied a variety of adapted technologies to produce volcanic reservoir economically. Horizontal wells can increase production and reserves by 4–6 times those of vertical wells, and longer wells are preferred. Specialized hydraulic fracturing techniques are suggested, including small or mixed proppant size, second HF treatment after proppant slugging, high-viscosity frac fluid with high-temperature resistance, special fluid loss reducer, high pump pressure, Extreme Overbalance Perforating, limited-entry fracturing, matrix acidizing, etc. Water control measures include producing below critical rates, partial perforation or penetration, controlling hydraulic fracture height, using horizontal wells, implementing complete cementing job, etc. Well productivity evaluation should be conducted to understand well performance and appropriately allocate production rates among wells, using the modified AOF method and other productivity prediction models considering breakdown fracture gradient, gas slippage effect, non-Darcy effect, etc. Well sites need to be selected based on recognizing profitable lithologies, lithofacies, high porosity and permeability, relatively developed fracture systems, thick net pay zones, etc. The critical questions for the industry are how to enhance volcanic reservoir recovery with more efficient and economic hydraulic fracturing and water control techniques. This is one of the first papers systematically summarizing the engineering technologies and unique solutions to develop volcanic reservoirs. Further and more complete reviews can be carried out in the future, and more novel and effective techniques can be explored and tested in the field.

New Mathematical Technique for Step Rate Test Analysis Aids Determination of Fracture Pressure and Overcomes the Uncertainty of Conventional Analysis.

Experience in the oil industry has shown that it is challenging to sustain successful long-term matrix injection, as injection water quality cannot be maintained rigorously due to facility hiccups and membrane clogging. Most oil field operators have resolved this problem of injectivity decline by increasing the surface injection pressure to part the formation and inject just above the fracture gradient with strict offtake management for zonal conformance. This is not an easy task as injection much above fracture opening pressure can lead to water fingering and poor sweep that results in uneconomical waterflood recovery. The operators, thus, strive to inject at a pressure just above the fracture opening pressure so that the fracture opens near the wellbore but does not extend and then maintain the pressure just above the fracture closing pressure. Therefore, determination of the fracture opening pressure and fracture closing pressure has remained critical data for the success of waterflood projects. The most reliable industry approach to estimating fracture opening and fracture closing pressures comes from the step rate test (SRT). This traditional approach of Cartesian analysis of pressure-rate plot fits straight lines through the data in a plot of injection pressure against injection rate and then estimates the fracture pressure from the intersection of these lines having different slopes. The data received often do not exhibit one clear change in slope, thus resulting in multiple possible solutions, making it difficult for the operator to use the data for high CAPEX facilities design. Most past studies indicate the subjectivity of this Cartesian slope fitting technique. Alternative solutions through multirate superposition analysis found limited application in the analysis of SRT data due to considerable sensitivity to the value of initial pressure used for superposition and lack of stability of rate and pressure data. In this article, a new technique of SRT analysis is presented, which provides a unique solution for fracture opening and fracture closing pressures. It helps to overcome the limitations of the traditional technique of arbitrary fitting of straight lines. It uses the mathematical understanding of cumulative derivatives to recognize that the matrix opens when the cumulative growth of the rate of injectivity shows a change. It estimates the derivative of the injection rate with respect to injection pressure at each step. Then, it estimates the fracture pressure from the plot of the cumulative of this derivative against pressure at each step. It helps to overcome the challenge SRT solutions posed by the nonlinear trend of pressure data at each injection step both before fracture and after fracture is initiated. It also overcomes the limitations of the multirate superposition technique, as it is not sensitive to the value of initial pressure used for superposition.

Wellbore stability in a depleted reservoir by finite element analysis of coupled thermo-poro-elastic units in an oilfield, SW Iran

Sustaining wellbore stability in depleted reservoirs is a crucial concern. With production from hydrocarbon reservoirs, the reservoir's pore pressure is reduced over time, and the reservoir is depleted since field development is one of the main purposes for oil companies. Heavy mud weight in depleted reservoir caused fracture due to reduced fracture gradient, and low mud weight caused blow out in high-pressure zone or well collapse due to shale beds that required high mud weight to prevent collapse. Considering geomechanics and coupled equilibrium equation, continuity equation, Hook’s law, compatibility equation, Darcy’s law, and thermal relation, the Thermo-poro-elastic equation was derived in this research. A finite element method has been designed to execute the fully coupled thermo-poro-elastic non-linear models. The finite element model was validated by analogizing it to the available analytical solutions for the thermo-poro-elastic wellbore troubles in shale. The non-linear thermal-poro-elasticity finite element model was used to analyze wellbore stability in a depleted limestone reservoir during drilling. The numerical results showed that a decrease drilling fluid’s temperature (cooling) causes to increase in the potential for tensile failure and reduces the potential of shear failure. Due to the depletion reservoir, the potential of tensile failure increased than shear failure, so heating the drilling fluid could cause wellbore stability in the depleted reservoir. Furthermore, based on the numerical results, it may be supposed that the drilling fluid’s temperature is one of the essential elements in the wellbore stability analysis in depleted reservoirs.

Sour-Rated 10,000-psi System High-Temperature Gas Development Wells: Sustaining the Malaysian National Gas Supply Through a Journey of Optimization in North Malay Basin

Summary High temperature (HT), high carbon dioxide (CO2) coupled with hydrogen sulfide (H2S) contents, and rapid pore pressure fracture gradient (PPFG) pressure ramp increase in gas development wells can lead to significant capital expenditures for operators. Such wells typically need high corrosion resistance alloy material with at least a 10,000-psi (10-ksi)-rated system to complete. The deep reservoirs of the North Malay Basin, offshore peninsular Malaysia, also fall into the described category. In this paper, we aim to share the optimization journey, applications, and learnings of the company’s HT sour-rated 10-ksi gas development wells through several phases, besides fulfilling the gas delivery need for the country. In addition, we identify engineering and operational optimizations to reduce the well’s time and cost while upholding the safety of the crew as a top priority. The sour-rated HT gas development campaign for the company began in the year 2017, followed by a second campaign in the year 2018. Our focus centers on the third campaign, which concluded in the year 2022. A total of four, three, and four wells were drilled and completed in the first, second, and third campaigns respectively. The company’s wells engineering team applied Lean methodologies that covered the entire Plan-Do-Check-Adjust cycle to achieve optimization. Using well data, learning from experiences, working together, maintaining consistency, and pursuing ongoing enhancements are the main factors that ensure positive optimization outcomes. Fit-for-purpose drilling and completions equipment design and application, rig offline capabilities planning, wellhead dummy hanger plug design for offline cementing, intervention-less production packer setting device, offline annulus nitrogen cushion fluids displacement, and other applications will be explained in the paper. In this paper, we describe the operational challenges faced and outline the applied optimizations that led to significant improvements in the well performance compared with targets and previous campaigns. The optimization efforts by the wells team extended from the engineering phase to the execution stage, including the use of in-house digital capabilities to monitor well performance, in alignment with industry practice. The recent campaign post-optimization concluded with no safety incidents, average per well more than 48 days ahead with 39% lower cost than previous campaigns, average of 5.6% overall well nonproductive time (NPT), and achieved first gas to meet the country’s power generation demand. Furthermore, the motivating optimization results also coupled with 25% more production results compared with the prognosed. The positive results of this optimization journey were significantly influenced by transparent, collaborative, and proactive communication across different departments.

Estimation of the Fracturing Parameters and Reservoir Permeability Using Diagnostic Fracturing Injection Test

The term "tight reservoir" is commonly used to refer to reservoirs with low permeability. Tight oil reservoirs have caused worry owing to its considerable influence upon oil output throughout the petroleum sector. As a result of its low permeability, producing from tight reservoirs presents numerous challenges. Because of their low permeability, producing from tight reservoirs is faced with a variety of difficulties. The research aim is to performing hydraulic fracturing treatment in single vertical well in order to study the possibility of fracking in the Saady reservoir. Iraq's Halfaya oil field's Saady B reservoir is the most important tight reservoir. The diagnostic fracture injection test is determined for HF55using GOHFER software. Models for petrophysics and geology were calibrated using the diagnostic fracture injection test results after the petrophysical and geomechanical parameters of the rock have been determined. The HF55 vertical well, which penetrates the Saady reservoir, has well logs that have been used to evaluate the petrophysical and geomechanical parameters. These estimates have been supported by findings from the diagnostic fracture injection test through the utilization of standard equations and correlations. The findings of the diagnostic fracture injection test, often known as the diagnostic fracture injection test, are very compatible with the findings of the well logs. The diagnostic fracture injection test pre-falloff test event was examined to determine the instantaneous shut-in pressure and fracture gradient. In the meantime, Closure pressure, process zone stress, fracturing fluid efficiency, closure gradient, critical fissure opening pressure, storage correction factor, permeability, and pressure-dependent leak-off coefficient were all determined using the G function on plot. With the help of a specific software, the petrophysical and geomechanical properties of a single vertical well [HF55] was found. Saady B reservoir's upper and lower sections, along with it are therefore predicted to have the full range of petrophysical and geomechanical features. With the use of DFIT analysis, these features serve as the foundation for developing fracturing models.

Study Makes Value Proposition for Carbon-Neutral Fuel From Light Tight Oil

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5437, “Carbon-Neutral Fuel From Light Tight Oil: A Value Proposition,” by Christine A. Ehlig-Economides, SPE, University of Houston. The paper has not been peer reviewed. _ Emissions for light tight oil often begin with associated gas. Rather than flare the stranded methane, an option may be to use it to power capture of CO2 from the air using direct air capture (DAC) technologies. This study catalogs global gas/oil ratio (GOR) data to identify currently produced light crude oils that could be rendered carbon-neutral through the DAC mechanism. It then considers operational aspects, including proximity to a suitable location for a DAC unit and proximity to subsurface utilization or storage opportunities, that favor or discourage this approach. Introduction Previous work by the author defined carbon-neutral crude oil (CNCO) as crude oil that has offset the CO2 to be emitted by its combustible products before its arrival at the sale point. Other authors refer to enhanced oil recovery (EOR) using anthropogenic CO2 and including monitoring, verification, and reporting as EOR+. They describe three EOR+ categories: conventional, advanced, and maximum storage. Conventional storage minimizes CO2 use to reduce cost, resulting in net usage of 0.3 t CO2/bbl. Advanced-storage miscible flooding follows current best practices for optimized oil recovery and also may involve some “second-generation” approaches that boost CO2 use, resulting in net usage of 0.6 t CO2/bbl. Maximized storage effectively uses the reservoir pore space for additional CO2 storage without additional oil production and may include removing water, resulting in net usage of 0.9 t CO2/bbl. CO2 Capacity The pore-space requirements for saline aquifer CO2 storage depend on whether primary or secondary storage is envisioned for the short term. Primary storage entails bulk CO2 injection into an aquifer storage volume effectively limited by interference with neighboring injection wells, while secondary storage entails producing the same volume from the reservoir as is injected as CO2. The bulk rock volume required to store CO2 dissolved in brine is approximately 200 times the original coal volume (Fig. 1). Limiting the injection pressure below the fracturing pressure to avoid breaching the caprock, however, further limits the CO2 storage capacity to approximately 6% of the pore space. This makes the multiplier nearly 120 times the original coal volume without CO2 dissolution. Generally, CO2 captured from stationary point sources and stored through multiwell bulk injection in a saline aquifer has a primary storage capacity of approximately 4.2 t CO2/acre-ft without increasing the original aquifer pressure. Three tables in the complete paper list inputs for these estimations and parameters derived from these inputs for cases corresponding to primary and secondary storage without aquifer pressurization. If CO2 injection elevates the aquifer average pressure, this increases the risk of inducing earthquakes and fracturing through the caprock. Using a typical fracture gradient of 0.7 psi/ft, injectivity of 3.23 BOPD/ft/psi could enable elevating the aquifer average pressure to 6,297 psia, which would, in turn, enable increasing the primary storage capacity to 18 t CO2/acre-ft and secondary storage capacity to 135 t CO2/acre-ft, again without CO2 dissolution. It is useful to compare maximized EOR+ with secondary CO2 storage in a saline aquifer. Effectively, maximized storage is like secondary saline aquifer storage in a sealed and trapped reservoir volume. Elevating pressure can increase the storage efficiency in either case, though with associated risks.

Surfactant Enhanced Oil Recovery Improves Oil Recovery in a Depleted Eagle Ford Unconventional Well: A Case Study

Summary A simple huff “n” puff (HnP) injection and flowback using a nonionic surfactant solution to drive enhanced oil recovery (EOR) in a depleted Eagle Ford “black oil” unconventional well has been executed and analyzed. The pilot injection was performed in December 2020, with pressures below the estimated fracture gradient. More than 12,300 bbl of surfactant solution were injected into the 6,000-ft lateral. In January 2021, the well was put back on production with oil and water flow rate data being gathered and samples collected. Within 3 months of the well being put back onto production after surfactant stimulation, the well produced at oil rates over five times what it had produced before stimulation. The current oil rates (through October 2022; 22 months after stimulation) are still twice the prestimulation rates. Using a long-term hyperbolic fit to historical data as the “most likely” production scenario in the absence of stimulation as a “baseline,” incremental recovery was estimated using the actual oil production data to date. Economic analysis with prevailing West Texas Intermediate (i.e., WTI) prices at the time of production and the known costs of the pilot result in project payout time less than 1 year and project internal rate of return in excess of 80%, with only incremental production to date. These results prove the potential for technoeconomic viability of HnP EOR techniques using surfactants for wettability alteration in depleted unconventional oil wells. The well was chosen from a portfolio of unconventional Eagle Ford black oil window wells that were completed in the 2012–2014 time frame. The goal of the test was to demonstrate successful application of laboratory work to the field and economic viability of surfactant-driven water imbibition as a means of incremental EOR. The field design was based on laboratory work completed on oil and brine samples from the well of interest, with rock sampled from a nearby well at the same depth. The technical and economic objectives of the field test were to (1) inject surfactant solution to contact sufficient matrix surface area that measurable and economically attractive amounts of oil could be mobilized, (2) measure the amount of surfactant produced in the flowback stream to determine the amount of surfactant retained in the reservoir, and (3) prove the concept of using wettability alteration in conjunction with residual well energy in a depleted well to achieve economically attractive incremental recovery. Surfactant selection was completed in the laboratory using oil and brine gathered from potential target wells, and rock from nearby wells completed in the same strata. Several surfactant formulations were tested, and a final nonionic formulation was chosen on the basis of favorable wettability alteration and improved spontaneous imbibition recovery. The design for the pilot relied on rules of thumb derived from unconventional completion parameters. Rates, pressures, and injectant composition were carefully controlled for the single-day “bullhead” injection. Soak time between injection and post-stimulation restart of production was inferred from laboratory-scale imbibition trials. Post-stimulation samples were gathered, while daily oil and water rates were monitored since production restart. Flowback samples were analyzed for total dissolved solids (TDS), ions, and surfactant concentration.

Expertise in Complex-Well Construction Leveraged for Geothermal Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 204097, “Constructing Deep Closed-Loop Geothermal Wells for Globally Scalable Energy Production by Leveraging Oil and Gas Extended-Reach Drilling and High-Pressure/High-Temperature Well-Construction Expertise,” by Eric van Oort, SPE, Dongmei Chen, SPE, and Pradeepkumar Ashok, SPE, The University of Texas at Austin, et al. The paper has not been peer reviewed. _ In the complete paper, deep closed-loop geothermal systems (DCLGS) are introduced as an alternative to traditional enhanced geothermal systems (EGS) for green energy production that is globally scalable and dispatchable. The authors demonstrate that DCLGS wells can generate power on a scale comparable to that of EGS. They also highlight technology gaps and needs that still exist for economically drilling DCLGS wells, writing that it is possible to extend oil and gas technology, expertise, and experience in extended-reach drilling (ERD) and high-pressure/high-temperature (HP/HT) drilling to construct complex DCLGS wells. Introduction CLGS is considered a subset of EGS, but the authors write that it is a distinct entity. EGS mostly involves well designs that rely on fractures for heat extraction. Such systems are different from CLGS wells in that the latter use closed conduits for thermal fluid circulation and heating. CLGS relies on fluids pumped through a closed loop. The authors treat CLGS systems as being different from EGS systems, with the understanding that drilling technologies discussed in the paper as enablers for CLGS wells apply equally to EGS wells. In the geothermal (GT) domain, the majority of attention and funding currently is assigned to EGS projects. A case is made in the complete paper to continue to develop DCLGS technology because of its favorable risk profile compared with EGS. Part I of the complete paper introduces a hydraulic model coupled with a thermal model suitable for calculating the power generation of DCLGS wells. This synopsis concentrates instead on Part II of the complete paper, in which technology gaps and needs of DCLGS drilling and well construction are highlighted and opportunities identified where oil and gas experience and technology can be directly applied and leveraged. Similarities and Differences of Deep GT and Oil and Gas HP/HT Wells - GT wells generally use larger production hole sizes than typical land wells. - Casing-cement annuli typically are cemented back to surface. - GT wells can be drilled in more-forgiving pore-pressure fracture gradient (PPFG) environments with wider drilling margins than geopressured HP/HT wells in hydrocarbon systems. - Severe lost circulation appears to be a universal problem in deep GT wells. - Drilling costs can account for 50% or more of the total capital costs for a GT energy project. - Data sets on GT wells are much smaller than those for oil and gas wells.

Jasmine: the challenges of delivering infill wells in a variably depleted HPHT field

Drilling infill wells into a heavily depleted reservoir poses several challenges that can lead to increased time, cost and risk. Data acquisition, including gathering formation pressure data, can be severely compromised, complicating real-time decisions and pore pressure interpretation. Fracture gradients, usually constrained by data acquired outside the reservoir, need to be estimated using a different approach through a depleted reservoir. The Jasmine high-pressure high-temperature (HPHT) field in the UK Central North Sea can be used to illustrate some of these challenges and to describe some practical solutions. A qualitative approach to estimating the level of reservoir depletion from formation gas measurements has been developed for the Jasmine Field, comparing pre-depletion gas trends against those obtained during the infill drilling campaign. The methods described here to estimate depleted fracture gradients using modelled and observed stress paths coupled to the pore pressure reduction were found to fit with well observations, and have helped to inform operational decisions to manage severe lost circulation events. A strategy to acquire data in memory while drilling has proved successful and has allowed lost circulation events to be managed safely. Managed pressure drilling has opened up narrow drilling windows, and has reduced the number of hole sizes and liners required to drill these infill wells. Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/topic/collections/geopressure

Development and evaluation of fracture gradient curve model: a case study of south-central Kazakhstan

An accurate fracture gradient value is one of the most important issues in oil and gas well design and drilling. The value of a fracture gradient is a critical parameter for determining the drilling mud weight and selecting the proper depths for setting the casing in the planning process of drilling operations. This paper proposed the new curve model of fracture gradient for the south-central Kazakhstan (central Asia) region based on the analysis of leak-off test and format integrity test results. Data from more than 400 tested wells were analysed and compared with the results of existing methods for predicting the fracture gradient and with the results from previous drilling projects in that region. By using the new curve model, the more precise values of fracture gradient are determined. Besides an improved fracture gradient model development and validation, the model's analytical expressions are presented. The article's most important results are determining the model's values of fracture gradient and providing a more accurate calculation of mud weight, less mud losses, more precise evaluations of cementing operations, better selection of the casing setting depth and improved drilling safety. [Received: February 13, 2022; Accepted: June 2, 2022]

Plugging efficiency of flaky and fibrous lost circulation materials in different carrier fluid systems

Lost circulation is one of the most significant contributors to wellbore instability and causes an increase in drilling operation costs. It is also a major contributor to the nonproductive time and must be minimized for improved economic and operational performance. The objective of this research is to provide tools and information about specific loss circulation management techniques that drillers can use to minimize lost circulation. This study involves comprehensive approaches to test the plugging efficiency of three different lost circulation materials (LCMs) from two groups of materials (flaky and fibrous). It also highlights the carrier fluids (drilling fluids) and the determination of the optimum drilling fluid properties. Different fracture sizes and the effect of the various LCM are analyzed. The impact of LCM’s shape, size, and physical and chemical properties along with the fracture sizes is discussed. Examining the particle size distribution before and after mixing with the fluids shows the capability of the materials in plugging the fracture while maintaining the minimum porosity and permeability of the plug. It also helps to strengthen the fracture gradient of the formation by knowing the actual particle sizes. The primary objective of this work is to precisely study and analyze these factors on the three LCMs along with different carrier fluids to investigate their plugging efficiency and potentially resolve or minimize the severity of the lost circulation problem.

Flowback rate-transient analysis with spontaneous imbibition effects

Analysis of flowback data, gathered immediately after fracture stimulation, can be performed to understand the fluid flow physics, investigate flow regimes, and obtain early estimates of fracture properties. During a hydraulic fracturing treatment, significant amounts of fracturing fluid will leak-off from the fractures into the reservoir due to Darcy flow, capillary, osmotic and electrostatic forces. Capillary invasion of fluids into the reservoir can cause a loss in gas relative permeability, leading to an altered zone near the fracture-matrix interface, therefore impeding the flow of hydrocarbons into the fracture. Due to this phenomenon and other fluid transport mechanisms, a simple application of Darcy's law might not be adequate for describing the fluid flow physics when solid-liquid interaction is significant. To overcome some of the above limitations, spontaneous imbibition effects are modeled at the fracture/matrix interface during the flowback period in this study.This paper presents a semi-analytical model for analyzing two-phase water and gas flowback data, when spontaneous imbibition occurs. This model was developed by solving the fracture and reservoir matrix flow equations simultaneously. The effects of fracture and reservoir matrix pressure gradients on gas and water influx at the fracture-matrix interface are accounted for in order to evaluate the reservoir matrix hydrocarbon influx. The proposed model accounted for spontaneous imbibition driven by capillary forces by quantifying the fluid influx due to capillary processes and adding it to the mass flow equations. Further, capillary pressure effects were incorporated into the PVT properties of matrix pseudovariables. The average phase pressures in the fracture and matrix were calculated iteratively using a modified material balance approach.The proposed semi-analytical model was successfully verified using fully-numerical simulation data. Practical application of the proposed model was then demonstrated using production data from a multi-fractured horizontal well.