bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Damage in CO2 Storage Wells – The Same, But Different
Authors: Byrne M. , Gilbert R. , Anderson R. 
Published: February 2024

Abstract
In many respects formation damage challenges in CO2 storage wells are similar to those in conventional oil and gas production wells and water and gas injection wells. But there are some differences from "conventional" well formation damage challenges. This paper outlines some issues specific to CO2 injection wells and proposes changes in focus prior to and during drilling and completion of these wells.
CCS (Carbon Capture and Storage) store can generally be split in to two categories – saline aquifers and depleted hydrocarbon reservoirs. Wells drilled and/or completed in these stores share some well injectivity challenges with conventional wells but also have some challenges specific to the store properties. In conventional injection wells it is generally accepted that well clean-up or back production prior to injection is beneficial as formation damage necessarily induced during well drilling and clean-up may be partially or fully removed. For saline aquifers and depleted hydrocarbon stores, well clean-up is normally not possible or practical. Direct injection after well completion is often required.
A new workflow capturing the key steps required to assure optimum well injectivity over the well life cycle has been developed and will be outlined in the paper. This includes but is not limited to: detailed analysis of CO2 phase behaviour in and beyond the lower completion; lower completion selection criteria specific to CO2 stores; laboratory testing and modelling focussed on CO2 store formation damage challenges; direct injection challenges and successful mitigations; ice scale and hydrate challenges in CO2 storage wells.
With increasing focus on CO2 storage globally, the workflow outlined presents an integrated approach to formation damage challenges. It demonstrates that although many of the challenges are similar to those in conventional wells, there are also some that are different and unique – the same, but different!
Analyzing Gas Well Productivity Change with Production in Unconsolidated Sandstone Using Rate Transient Analysis
Authors: Kumar Anand , Marandi Pratik , Verma Deepak 
Published: February 2024

Abstract
The primary objective of this paper is to demonstrate the changing productivity of the cased hole gravel packed gas wells due to wellbore matrix disturbance, rapid bean up operations and how daily production data (rates and flowing pressures/ temperature) can be used to analyse gas well performance along with estimation of Gas In Place. This work includes the identification of well problems and productivity changes, attributed to wellbore matrix disturbance or sub-surface issues in unconsolidated sands.
The analysis method used in this work is Rate Transient Analysis along with Pressure Transient Analysis. Bottom hole temperature behavior and Decline Curve analysis are also analyzed to validate the results captured from RTA. RTA is ideal for establishing a well's productive capability early in its life (after 3-6 months) and categorizing subsequent well decline behavior as either reservoir depletion or productivity loss through time (or a combination of the two). Through interpretation of diagnostic plots, such as the Flowing Material Balance Analysis and Type Curve Analysis plots, specific productivity issues can be easily identified and classified using simple pattern recognition.
Field examples from multiple gas wells across KG Offshore Deep Water (Water depth &gt; 400m), completed with cased hole gravel pack, are included in our study. The present case study indicate the apt use of RTA, PTA and other bottom hole parameters to determine current K, changing skin & the most important GIIP of single well gas fields. RTA will supplement and to some extent give the actual estimation with less error. Deliverability issues such as wellbore matrix disturbance and gravel pack degradation associated with unconsolidated sands are identified. The issues has been validated by flowing temperature behavior. Results show how RTA can be used as a practical screening tool, identifying underperforming wells and quantifying the potential benefits of remedial action based on remaining reserves.
This paper presents a novel application for RTA - as a screening tool for diagnosing underperforming wells and estimating their optimum producing rates. The industry tends to undervalue the potential benefit of all but the simplest remedial measures for underperforming producing wells for two reasons- 1. Poor performance is often simply accepted as a statistical reality and 2- operators do not even realize that their wells are underperforming. In case of deep water, work over job or drilling new well is a very costly affair. Also, time plays a major role in economics of a development project. If the issue(s) can be resolved, production improvements aggregated field-wide could have tremendous economic implications.
Technology Optimization and Field Test for Improving Development Effect of Deep Low-Permeability Water-Sensitive Reservoirs
Authors: Yang L. L. , Long H. , YUAN A. W. , LUAN R. Z. , Yang X. , Liu P. H. , Ren Y. L. , Wu X. M. 
Published: February 2024

Abstract
The main focus is on exploring the optimal gas injection development model for deep, low permeability and water sensitive reservoirs. The technical limit of liquid CO2 injection was defined, which would effectively guide injection parameter design. A new type of anti-corrosion and gas-tight injection string were designed, which would assure safe and efficient injection. The successful field test provided an effective energy replenishment method for deep, low permeability and water sensitive reservoirs, and also provided technical reference for the effective utilization of other similar reservoirs in the next step.
Engineering for Success: Design and Execution of Fluids for Optimum Injectivity - A Case Study
Authors: Storli Christer , Asko Arne , Twynam Allan , Hovem Knut , Knox Dave , Thibodeaux Brittany Granger , Cascone Alessandro , Kamel Abdalla 
Published: February 2024

Abstract
Two North Sea water injector wells have achieved high matrix injectivity rates without backflow to clean-up prior to commencing injection. Achieving successful results on direct water injection wells is recognised as a technical challenge, requiring detailed design and validation work around the selection and execution of the drilling and completion fluids. Engineered water-based reservoir drilling fluid and post-drilling chemical "breaker" treatments were utilised for these open hole screen completions.
The technology around the use of breaker fluid has evolved in recent years, yet successful application is challenging when two objectives are combined; achieving the required injection rate without clean-up flow prior to injection and keeping the injection pressure below the minimum fracture gradient for uniform matrix injection over the full length of the completed interval.
Once suitable fluid formulations have been identified and validated by laboratory testing, detailed engineering procedures are required to ensure that the fluids are maintained within tight design specifications through the execution phase. For example, one critical key to success is ensuring that formation solids and residues incorporated into the drilling fluid are minimised to reduce the risk of plugging the matrix permeability. Once the well is drilled, ensuring that the breaker fluid is placed across the entire zone of interest and the filter cake is removed in a controlled and uniform manner facilitates good injectivity results.
This paper describes; the technical challenges presented by this project, the extensive laboratory testing performed as part of front-end engineering and design, an overview of the field execution across the two water injector wells, the results and the lessons learned.
Iron Sulphide (FeS) Scale Prediction-Modelling Development and Experimental Methodology Design
Authors: Jarrahian K. , Sorbie K. S. , Azuddin F. J. , Ness G. 
Published: February 2024

Abstract
Iron sulphide (Fes) scale is widely present in both oilfield and geothermal systems and causes a range of production and Health and Safety problems. Although substantial progress has been made, continued efforts are needed to precisely understand and predict FeS scaling. The aim of this work is to present a simple robust model for FeS scale experiments in the laboratory. This model predicts saturation ratios (SRs) and masses of the formed iron sulphide scale, final solution compositions and final pH levels, for specific lab experiments. This model is verified by comparing results with carefully designed experiments which are monitored by a range of analytical experimental techniques, e.g., ICP-OES, ESEM/EDX and XRD (explained in the text). These analytical methods allow us to analyse for all the components present, such as initial and final [Fe2+], aqueous [H2S] levels etc, and they also give direct information on the morphology of any precipitates formed, either as crystalline or amorphous solids.
Experiments were performed in an anaerobic chamber since we were using iron (II) ions (Fe2+) from both iron (II) chloride tetrahydrate and also ammonium iron (II) sulphate hexahydrate. The latter, known as Mohr salt, is thought to be a more reliable source of Fe2+. In fact, we found different crystallographic types of FeS scale precipitate from each of these 2 irons (II) salts.
In addition, we observed that when FeS particles are precipitated from the solution, then under some circumstances some FeS particles can remain in colloidal suspension. This has implications for the level of measured "[Fe2+]" by ICP which measures the total Fe in solution, i.e., the free Fe2+ ions as well as any suspended colloidal FeS. The results show that there is a quantitative agreement between the experimental results and the predictions of the model in determining final pH of solution, final [Fe2+] and mass of FeS precipitate. However, it was also noted in some cases where discrepancies occurred – e.g., in [Fe2+] level – this may be ascribed to the colloidal nature of FeS scale.
The information presented in this study will help production chemists to understand the chemical formation of FeS in laboratory testing, and this will assist in the selection and design for future scale inhibitor treatments.
Mechanistic Modeling of Wellbore Integrity During CO2 Injection in Deep Saline Aquifers
Authors: Ali Khan Jawad , Michael Andreas 
Published: February 2024

Abstract
In this paper, we examine wellbore integrity during carbon dioxide (CO2) injection in deep saline aquifers, by modeling stress-distribution evolutions within the casing-cement sheath-rock formation (C/CS/RF) system. For our analysis, a mechanistic model is used, which considers a total of eleven ("10 + 1") modes of mechanical degradation assessing each of the three layers of the C/CS/RF system discretely.
The integrity of the wellbore is assessed by modeling the casing layer as a thick-walled cylinder and the adjacent-RF layer as a poroelastic solid, accounting for fluid infiltration into and out of the pores in close proximity to the CS layer. The magnitude of the normal-effective stresses at the C/CS and CS/RF interfaces provide calibration parameters for the stress distributions within the intermediate-CS layer, honoring linear elasticity. This novel method is used to determine the initial state of stress within the C/CS/RF system with balanced conditions inside the wellbore, following cement setting. Using input data from the literature, the integrity of the C/CS/RF system is assessed over a 30-year period of bulk-CO2 injection in a closed (bounded) system and an open (unbounded) system subsurface aquifer.
In closed-aquifer configurations, disking failures along with radial and shear cracking tendencies are indicated within the CS layer, providing potential pathways for CO2 leakages back into the atmosphere. In open-aquifer configurations, the three aforementioned tendencies for mechanical degradation remain, albeit at a smaller degree. The generated stress distributions demonstrate no indication of inner debonding along the C/CS interface, while the outer-debonding limit is approached on the CS/RF interface, but never exceeded. Moreover, no tensile failures (via longitudinal or transverse-fracture initiation) is expected along the CS/RF interface, nor casing failures (related to compressive/tensile loads, collapse and burst stress loads). Finally, none of the scenarios considered are expected to generate seismic activity along preexisting faults (PEFs) near the injection well.
A Case Study of Enhancing Reservoir Performance Through Protecting the Matrix
Authors: Cottingham Byron , Ph.D. Charles Landis, , Jordan Josh , Hall Chad 
Published: February 2024

Abstract
The North American oil and gas industry continues to focus on smaller pore space and there is a continued need to protect and enhance the pore space and fracture networks in our reservoirs. To achieve this, our team has developed and tested a new category of bio-based embedment control fluid additives, that has shown to directly improve reservoir performance after flowback by slowing the reduction of fracture conductivity in hydraulically fractured rock.
Unconventional reservoirs are mineralogically complex. There is an array of minerals that are sensitive to invading waters including 2:1 layer silicates; "clays", oxides, substituted carbonates and freshly fractured silicates like quartz and feldspars. In North America, the clay fraction of the major plays is largely barren of discrete smectite, thus common clay control additives or the use of produced water brines for this purpose is poorly justified, and in fact promotes sloughing of the finest fractions from the fracture face (Landis et. al, 2018). In addition to fracture face softening, fines generation is a pronounced risk factor in reservoir damage mechanism especially with the use of common clay control additives.
To address this problem in our industry, the team functionalized bio-based polymers to maximize polydentate encapsulation of fluid sensitive minerals on the fracture face. This interaction is exploited to reduce reservoir damage in the crucial early stages of the stimulation process.
Molecular design, regain permeability testing and, finally, controlled field applications of the embedment control additive are shown in this paper to provide new realized value in the first year of production and beyond. The new bio-based additive differs from other higher molecular weight polymers used in the stimulation process. Smaller linear molecules functionalized with inhibitive substituents that do not exchange with the cations or anions in the mineral structures. When compared the larger polymers used for friction reduction, the targeted approach for the most interactive sites along the fracture face are addressed preferentially.
A more direct indicator of embedment control is obtained with regain permeability analyses. Assessment of the new bio-based product was conducted on Wolfcamp landing zone facies, and the Eagle Ford formation targets. All tests were run at representative confining pressures and temperatures, and against KCl baselines. A case study was performed in the field and highlighted the product's capability with both a reduction in turbidity during flowback by 350%, and production enhancement of the wells performance indicating the potential of increased performance with proper reservoir protection. In summary, this paper highlights the need for reservoir protection, a novel approach to minimize formation damage, and both laboratory and field testing of the process to prove the performance enhancement of minimizing formation damage.
Breaking Barriers: Revolutionary Acid Stimulation and Diversion Methods Unleash Offshore Brownfield's Oil Production Potential - Case Study from Gulf of Suez
Authors: Hakim Emad Abdel , Hegazy Amr , Ramadan Ahmed , Saleh Khaled 
Published: February 2024

Abstract
Dealing with the intricacies of carbonate formations presents significant challenges in enhancing oil production, particularly in offshore brownfields plagued by water breakthroughs in commingled completions. While mechanical diversion using straddle packers is a commonly employed method to achieve effective zonal coverage and selective matrix acidizing treatment, it is noteworthy that these mechanical isolation techniques tend to be more expensive compared to chemical diverters.
This paper outlines a comprehensive approach to improving production in such demanding scenarios. The strategy encompasses various factors, including addressing the root causes of water breakthroughs, formulating suitable acid chemicals, choosing effective chemical diversion methods, and optimizing the execution of the overall process. To illustrate the application of this approach, three candidates from the Gulf of Suez Basin, a complex and heterogeneous region in the Eastern Desert of Egypt with carbonate reservoirs, are examined as case studies.
A viscous pill underwent testing in the laboratory before transitioning to field applications. This pill was designed to temporarily isolate fractures or fissure networks, diverting the primary treatment away from water and/or thief zones before the acid treatment. The results of this innovative chemical diversion technique demonstrate a remarkable four-fold increase in well productivity, coupled with a reduction in water cuts.
This paper introduces the workflow and laboratory test results of a purpose-built acid and diversion technique explicitly tailored for fractured and watered-out carbonate reservoirs. Furthermore, it shares valuable insights and practical guidelines gleaned from the lessons learned while applying these methods, providing valuable guidance for future cases with similar challenges.
An Integrated Study with an Effective Strategy Leads to a Great Discovery in a Challenging Fractured Jurassic Reservoir in West Kuwait
Authors: BinSafar Ahmad , AL-Ibrahim Abdullah , Ayyavoo Mani Maran , Al-Otaibi Fahad , Ibrahim Anwar , Al-Khlaifi Omar 
Published: February 2024

Abstract
To overcome the challenges in drilling, completion and testing for one of the highly fractured reservoir in West Kuwait oil field by intercepting the natural fractures and eliminating the causes of formation damage. An integrated multi-disciplinary study was carried out, to understand the underlying drivers of success and causes of failure in Najmah/Sargelu (NJ/SG) reservoirs in west Kuwait area and propose solutions to improve the chance of success. High reservoir pressure, high API oil and the limited success in some areas suggest that this reservoir has significant potential, despite the poor matrix permeability. The key to well success is to intercept the natural fractures and connect them to the production system without damaging them. Various potential damage mechanisms have been encountered, including mud invasion, cement plugging, formation solids plugging and formation collapse. The previous wells were drilled vertically with heavy oil based mud (OBM) and completed with cemented liner against the zone of interest. The study has identified robust well types that are designed to intercept the maximum number of natural fractures with high angle and open hole section with un-cemented 5" slotted liner. In addition, the plan was to drill the wells with high angle (80°) in the Lower Najmah Limestone and Upper Sargelu Limestone Formations but due to some drilling difficulties the plan was changed to 50° only. Therefore, number of wells in west Kuwait were planned to be drilled and completed as per the above strategy.
The first well drilled and completed as per the new strategy did not reach the expectations after inconclusive test, and it needs to be revisited for better evaluation. The second well was drilled in a very challenging environment with high angle trajectory to encounter the natural fractures in the targeted zone. The un-cemented perforated liner was run and installed as planned, which eliminated the usual damage by cementation. During the well activation using Coiled Tubing and without any stimulation treatment, the targeted reservoir became active and the well showed commercial production of oil and gas with high well head pressure, which was announced as a great discovery in west Kuwait. This discovery is considered as a significant mark in Kuwait and opens a new window for exploring and developing of NJ/SG reservoir in other areas.
New drilling, completion and testing strategy was applied in the challenging Jurassic reservoir, which lead to a great discovery in the state of Kuwait. Detailed drilling, completion, testing strategy and production performance with the lessons learned will be discussed in this paper.
Breaker Placement in Sand Control Lower Completions – New Challenges and Potential Solutions
Authors: Byrne M. , Djayapertapa L. , Watson K 
Published: February 2024

Abstract
Production and injection wells for oil and gas and carbon storage reservoirs often require sand control across the reservoir section to enable fluids to flow and to prevent larger formation solids from moving. In many of these wells, chemical breaker treatments are pumped prior to production or injection to help to reduce any drilling or completion induced formation or completion damage. Delivering these breakers to the target such as residual drilling mud cake can be challenging and rules of thumb have often been used to guide this process. More rigorous methods to optimise breaker placement and design are now available.
CFD (Computational Fluid Dynamics) enables fluid flow in complex geometries to be modelled and predicted. Breaker placement during the well completion process involves the complex geometry of the well, the lower completion and the reservoir and fluid flow or displacement. The full geometry of vertical or horizontal wells, with induced fractures, multiple wellbores, perforations or mini-bores should and can be captured using CFD. Breaker pumping whether bull-headed, through a wash pipe, coiled tubing or more sophisticated rotating and jetting needs to be simulated in order to determine its efficiency.
Numerous simulations for different well types, completions and breaker deployment methods have revealed that even with the best intentions and rules of thumb, it can be challenging to place breaker to the target and for breaker concentrations required for efficient dissolution of residual damage to be maintained. In particular gravel packed completions present challenges. Fluids will always take the path of least resistance and in gravel packed completions this is often back up the well between the wash pipe and the screens missing the intended target. The additional resistance of the gravel in the annulus tends to prevent efficient breaker penetration to mud cake or perforations beyond. If the breaker does penetrate, then coverage of the damaged zone can be patchy and early losses can result. Simulations have also identified potential mitigations such as alternative deployment rates, displacement fluids prior to breakers and duration of breaker placement. The benefits of targeted breaker placement during pump and pull or jetting operations has also been evaluated.
Challenges in placing breaker effectively in sand controlled wells are addressed using complex numerical modelling. Replicating well geometry and all fluid flow paths are essential in order to optimise breaker placement and reduce residual formation and completion damage. The methods and examples shared will enable more effective clean-up of oil, gas, water, hydrogen and CO2 wells.