A newer trend in gel treatments is using preformed particle gels (PPGs) to reduce fluid channels through super-high permeability streaks/fractures. This work sought to determine what factors influence the blocking efficiency of PPG on fluid channels.

A transparent model was designed to observe the compression of gel particles in fluid channels at different load pressures to study the effect of different parameters on PPG blocking efficiency.

Permeable gel pack was formed in fluid channels by gel particles and its permeability depends on particle sizes, brine concentrations, and load pressure. Gel pack is compressed and its permeability is reduced as load pressure increases. The permeability of gel pack increases with the increase of particle sizes. The blocking efficiency of particle gels on channels will reduce if we select large sized or/and strong particles.

A gel pack which has a desired permeability can be designed by selecting proper gel at reservoir pressures.

The combination of two technologies- horizontal drilling and hydraulic fracturing- made it possible to produce shale oil reservoirs economically.Although the massive stimulation treatment is the primary solution to recover efficient amount of oil from shale oil reservoirs, the recovery factors of these reservoirs are expected to be around 5-10%.The enormous remaining oil volumes stimulate our efforts to investigate the application of enhanced oil recovery methods in shale oil reservoirs. In unconventional reservoirs, cyclic gas injection using various gases could be an effective technique. Since it is a single-well process, well-to-well connectivity is not required. The hydraulic fracturing provides a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix swelling the volume of oil and increasing the near wellbore pressure which helps increasing the oil recovery in the production stage of this technique. Experimental and numerical studies by Gamadi et al, 2013 and 2014, and Tovar et al 2014, have shown that there is a great potential of increasing the recovery factor from shale oil formation. Since the hydraulic fracturing provides a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix, we investigated the performance of Cyclic Gas Injection on acid stimulated shale oil cores. The aim of the acid stimulation treatment was to improve the low-permeability matrix of the shale cores. The results showed that the acid treatment cores resulted in improving the porosity and permeability, this improvement led to better recovery factors comparing to unstimulated cores. In the conclusion, the combination of acid stimulation treatment followed by cyclic gas injection led to improving the recovery factors of the shale cores to about 50 % comparing to the unstimulated shale oil cores used in previous studies by Talal 2013 and 2014.

Oil well cementing has come a long way since the first verified use of cement in oil wells in 1903 by Union Oil Company. The years that followed have seen a remarkable amount of research and technological innovation in fluid flow mechanics, cement rheology, cement additives and cement job procedure. Given its purpose, well cementing is perhaps the most crucial stage in the development of any oil or gas well and as such proper procedure and guidelines as well as adherence to regulations are necessary to ensure success. This paper presents a summary of recommended best practices for all the stages of a cement job, from slurry design and lab testing, to job design, execution and evaluation.

This work explains how to evaluate the different perforation parameters of the production vertical oil wells by using both reservoir and perforation information. We collected the necessary data from Hungarian oil wells including reservoir description data from the MOL Company files. We also collected the perforating guns data from the Schlumberger Company. We used four perforating HSD guns with different charge and explosive load design.

We used a calculation method to determine the perforation depth, the influence of the different composite skin effect (damage skin factor, crushed zone skin factor, and the perforation skin factor), than we evaluate the flow rate of the different kind of guns. After giving the detailed figures and results, we evaluate the results of the perforation work. In conclusion, Hungarian oil wells will improved their productivity by using high shut density guns. Flow rate evaluation needs a good knowledge of rock properties, and flow properties.

Various options are available for successful underbalanced well intervention.  This paper will compare two common methods, coiled tubing and snubbing (hydraulic workover), discussing each approach’s advantages, applications, and wellbore considerations in selecting an underbalanced intervention method.  In addition, unit specifications, basic calculations and selection criteria will be addressed.

Adequate preparation & design helps assure successful hydraulic fracturing.  This paper will discuss the basic information that goes into frac design including fluid type, proppant selection, and equipment requirements.  In addition, basic calculations, quality control and additional requirements for job preparation will be discussed.

Formation damage management and remediation are both a science and an art (Civan 1996). Currently, there are no proven technologies that are treated for all problems that an oil company may encounter. The issues revolving around formation damage is one of these convoluted issues which many oil companies currently struggle with. This paper has proposed such an innovative approach centered upon three dimensionless groups as well as multiple regression analysis using MINITAB (a statistical computing program) to foster an empirical model to predict skin factor for Field XXX which belongs to a Libyan Oil Company. The first step in this endeavor was employed by the use of data collection consisting of buildup data history and fluid properties from eight oil wells. A total of 39 observations were used in this study. Of these wells, 27 observations were used to develop the empirical model. The remaining 12 observations were chosen randomly to test the capability and validity of the model to validate the empirical model and test predictive competence, predicted skin factor values were compared against skin factor values determined from the buildup test analysis shown in Statistical evidence proved that the model illustrated in this thesis is advantageous and may potentially be utilized in efforts to predict of skin factor. Comparing the developed model predicted results to the observed buildup test results, demonstrations have shown that there is a correlation between the results and well ability of the developed model to estimate skin factor. As a result, this study offers the following conclusions: The size of the data set, used in the development of the empirical model, had significant effects on construction of the model, since the data used for developing the model must be good enough to increase the accuracy of model. In this study, 39 observations were used to form and test the model, which had six variables divided into three groups.   These 39 observations represent five years of the production history of eight wells. The developed model presented in this study has the ability to further assist understanding, and evaluating the formation damage by predicting skin factor. The developed model also has the potential use of predicting skin factor instead of conducting a buildup test every year. This will reduce operating unit technical cost (UTC), and save millions of dollars for the Libyan operating company. When the mechanistic or mathematical models correlating certain variables are unknown, statistical tools are shown to be useful in development of models correlating with two or more variables of concern.

The development of horizontal drilling combined with hydraulic fracturing has allowed operators to develop unconventional shale plays once considered uneconomical. As operators move toward longer horizontal and multilateral sections in these plays, the complexity with respect to well stimulation and completion systems increases. Before a well is stimulated or completed, critical problems can emerge, such as casing leaks. Depending on the well configuration, traditional remediation methods might be unable to withstand stimulation treatments, difficult to apply and/or create a restriction in the casing inside diameter. This paper discusses how an acid and abrasion resistant resin system was applied to remediate a tight leak in the multi-stage cementing tool of a 5.5 in production casing and enabled the operator to pass a pressure test and carry out the planned stimulation of the well in twenty-five stages, without any signs of a leak.

 Slickwater Fracturing has enabled us to penetrate deeper into tight formations than ever before. This presentation will discuss the basic fundamentals of  Slickwater fracturing with respect to the  base fluid,chemical additives, the frac process,the advantages and disadvantages of Slickwater, proppant placement, proppant selection, and Slickwater frac candidates. We will also give a brief description of the Equipment requirements to perform a Slickwater frac successfully and safely .By providing this information we will aid in the understanding how Slickwater transports proppant and places this proppant in the fracture.       

Oil and gas production is from conventional and unconventional formations, with both requiring some form of stimulation.  Limestone and dolomite are considered conventional formations which are stimulated with various treatments, either above fracturing pressure or below.  Treatments above fracturing pressure are hydraulically created cracks that use either proppant or acid to maintain flow paths after closure.  Treatments at pressures below fracturing use acids to create wormholes that penetrate into the reservoir bypassing any near wellbore damage.

This paper will provide an overview of the process that should be implemented in the design of an acid stimulation treatment to provide the best opportunity of successful production improvement.  Specifically being addressed are the criteria that defines the need for an acid fracture treatment over a propped treatment, staging and diversion to obtain better zone coverage, how to overcome temperature limitations, etc.

Modeling of hydraulic fracturing began after the early years of the first application of this technology. Since then, researchers have taken several modeling approaches and significant progresses are achieved in hydraulic fracture modeling. Developments are result of studying different complexities such as out of plane propagation, different problem scales, fluid flow, thermal stress etc. In addition to these complexities, uncertainty of the problem dictates the prediction of final fracture geometry before the real operation. Therefore, an effective modeling approach is needed to obtain a successful hydraulic fracture treatment. The objective of this study is to discuss the various approaches in hydraulic fracture modeling and present a review on history of hydraulic fracture model developments.

Simple 2D hydraulic fractures were among the early analytical models for prediction of fractures behavior. Inefficiency of these models for predicting fracture geometry in reservoirs with complex layers caused the development of so called P3D models. P3D short comes resulted in the development of fully 3D models with 2D fluid flow modeling capability. Several 3D models have been developed since then which include coupled fluid flow equations with fracture mechanics. Although 3D models gives more accurate results than other models, out of plane propagation was not considered in majority of them. They simply ignore the near-wellbore effects of deviated wells and assume a planar starting crack that has extended beyond this region. This problem was solved later using true 3D models.

Pump spacing on fiberglass sucker rods is very important to the performance of the well and fiberglass rods.  As gas becomes more of  a problem in pumps, the gas compression ratio is even more important.  Edge Production Equipment has developed a chart for pump spacing that will help space wells more efficiently and increase the gas compression ratio. 

A tried and true method of reducing gas interference in rod pumps is to set the pump in a position below all the perforations. The liquid and gas separate with the liquid dropping down to the pump intake and the gas rising in the casing-tubing annulus. This is not possible in today’s horizontally completed wells where the preferred pump placement is in the vertical section. In 2000 and an update in 2001 Benny Williams with Harbison Fischer presented papers regarding the then new Harbison-Fischer Variable Slippage Pump® (VSP®) patent #6,273,690 . In the last 24 months there has been an increase of interest of the VSP®. Many of these pumps have gone into these horizontally completed wells. The timing is good to update the paper with the large number of new wells being completed horizontally.

Once horizontal wells expend their phase of natural flow and an artificial lift system is required, they are well known to have production challenges associated with downhole pump gas interference and solids issues. Gas lift is often implemented as a transitional artificial lift solution since it is solids-tolerant, it can handle high decline rates and it can manage sluggy flow conditions inherent to horizontal wells. Producing fields with gas infrastructure frequently default to this option to capitalize on existing equipment, but knowingly sacrifice longer term production and reserves from the limitations of gas lifting.

This paper will present an approach to replace gas lift in the intermediate lifting cycle of the life of a well. The paper will discuss the limitations of gas lift, introduce an alternative approach and demonstrate its efficiency with case study.

In 2014, Hess initiated a project to manufacture 1-inch slim hole sucker rod couplings with a Cu15Ni8Sn high strength spinodal alloy, which provides higher toughness and corrosion resistance compared to other bronze alloys. 

The couplings significantly reduce wear in deviated sections of unconventional wells. Hess’s pilot program includes ten wells and will be extended to sixty wells. 

Another pilot is underway wherein ¾-inch full size couplings and 1-inch slimhole couplings are installed at the bottom half of three wells. The purpose is to reduce friction in the lower portion of the string, thereby lowering the peak polished rod loads, lowering gear box loads, reducing power consumption, and increasing pump stroke length. Results will be presented in the paper.

While controllers for VSD-driven pumping units have the capability today to make manually programmed intra-stroke speed changes, they do not autonomously make these decisions. This work will describe a new control algorithm that autonomously chooses polished rod velocity profiles to maximize efficiency and production while protecting pumping units and rods from overloads. The algorithm uses surface and downhole cards from the earlier stroke, generating a new polished rod velocity profile for the following stroke. In particular, the algorithm modulates ramp rates and peak velocities of a smooth ‘trapezoidal’ velocity profile. Simulations of this algorithm suggest that rod fatigue, rod buckling and load violations can be corrected, while maintaining production. Results from full-load tests will be presented to show how the algorithm morphs surface cards to fit the permissible load envelope of pumping units. Using such an algorithm, overall power consumption of rod pumping can be expected to decrease by 10-20%.

This paper will be on the use of high liquid volume plunger lift in the Permian Basin.  This method of lift was first considered in an effort to bridge the gap for taking high liquid volume wells from flowing to rod pump.  Historically in the Permian Basin this was accomplished with high cost electric submersible pumps, gas lift or rod pump.  One of the criteria for success was that plunger lift would be able to economically maintain a well on its natural decline.  Representative decline curves will be presented, along with operating pressures and histories on the successful wells.  This paper is will be an update of a previous paper presented in 2015 for wells in the Southern Delaware Basin.

In the West Texas Delaware Basin, at Anadarko, we are very early in our development of the Bone Spring & Wolfcamp formations. Our current artificial lift strategy is to use gas lift or jet pump as intermediate lift, followed by rod pump. We implement these methods of artificial lift to produce high total fluid volumes and reduce downhole failures. This presentation covers what we have learned so far and the questions that remain to be answered as we determine the most effective way to produce these wells.

The field trial is focused on utilizing a pilot valve to obtain low instantaneous FBHP for low rate, low reservoir pressure horizontal wells. The pilot valve system is an alternative use for a positive displacement pump application. The presentation will cover the operation and use of the pilot valve. As well as cover well application and total fluid rate recovery expected while on pilot valve intermittent service. Operational fixes, and improvements will be discussed and shown as a means to improve efficiency and reduce % loss during intermittent cycles. Production results from pilot valve tests will be indicated along with predicted FBHP to illustrate the change in FBHP and resulting drawdown from low reservoir pressure wells.

The values that can be obtained from understanding what problems or needs are required in resolving existing well performance are often not taken into account when applying solution treatments. Upfront in Best Practices, Diagnostics may be required to (A) identify well integrity issues, define the various well or reservoir conditions, or they may be needed to (B) define and develop a solution required to fix the various understood problems that may occur.

The mission of the Texas Board of Professional Engineers (Board) is to protect the health, safety, and welfare of the people in Texas by ensuring that the practice of engineering in the state is carried out only by those persons who are proven to be qualified and by regulating the practice of Professional Engineering in Texas. 

The course provides a review of engineering ethics and professional responsibilities while highlighting important aspects of the Engineering Practices Act Rules and Regulations.  The one hour presentation also provides P.E.s the required one hour Continuing Education Credit for Ethics, Rules and Regulations as well as informs any Engineer on updated information related to the practice of engineering in Texas.

The theoretical studies and experimental data of two-phase flow hydrodynamics currently available are mainly for the case of horizontal, inclined, and vertical flows.  There are some developments to understand the two- and three-phase flow hydrodynamics on the hilly-terrain and the severe-slugging in both onshore and offshore cases.  Yet, for the cases of horizontal well with the production tubing inside, the impact of the tubing location in the horizontal well at the curve section (the connection between the vertical and horizontal sections) are not clear.  This work provides the review on the two-phase flow hydrodynamic characteristics for the case of horizontal well and provide the fundamental understanding on the impact of toe-up and toe-down of the well to the case of two-phase gas-oil flows. The review also emphasizes on the applicable two-phase flow steady-state and transient models that can be using to analyze the horizontal well production successfully.

Excess water production is a wide-spread and costly issue in the oil and gas industry. Polymer gel water shutoff treatments provide a valuable means of decreasing water production and reducing operating costs; however, successful treatments are dependent upon selecting viable candidate wells. The industry has long sought a reliable means of identifying wells to target with polymer gel treatments. Most studies into this problem have looked into a potential link between formation permeability and the success of treatments. This paper explores a new method: a correlation which uses the porosity and height of the treated zone to evaluate the viability of polymer-based water shutoffs.

This study proposes a selection method for water shutoff candidates in a dolomitized, oolitic highly-permeable carbonate reservoir in the Grayburg formation. Wells completed in this field often have issues with a high water-oil ratio (WOR), creating a need for water shutoff. The candidate selection method took shape while reviewing the data of several recent treatments in the field. The selection method is based on the formation porosity and height (ϕH) of the treated interval. It is proposed that a ϕH value within a given range is indicative of a potentially-successful treatment.

Once the initial idea was defined, the results of the first wells were compared to the proposed correlation. Using the function to identify candidates, additional wells were selected and treated. Results of these wells are presented in the paper and support the proposed model. For additional confirmation, the method was applied to the data for a series of wells treated with polymer gel in the same formation and field in 1997-8. The results of this study are also presented.

Polymer gel treatments have valuable water shutoff capabilities, but they must be applied to the correct candidate wells. The correlation presented in this study provides a system by which wells can be selected for treatment. This paper will demonstrate the viability of the method in a classic carbonate reservoir with high permeability variations.

The purpose of this study is to observe the effects of superabsorbent polymers AT-O3S and 2G-110 when introduced to brine solutions with varying pH values.  The polymer is intended to swell in order to block high permeability zones in existing oil wells.  The swelled polymer will decrease reservoir heterogeneity, diverting injected water to the oil rich zones/areas. Understanding the kinetics of the SAPs are crucial to their proper employment. However, when the AT-O3S and 2G-110, both Sodium crosslinked polyacrylic acids, are introduced to brine solutions containing Calcium, reactions involving the sodium crosslinker of the polymers occurs resulting in the destruction of the polymers.  To remedy this situation, we are testing if varying pH values of the brine will alter the reaction in order to find whether or not this problem is preventable.  Our results have been positive in that the reaction was delayed as the polymer precipitated out slower.

Tight oil reservoirs have become one of the main forces of oil reserves and production growth. Tight oil reservoirs are mostly developed by natural depletion. Only 5 % to 15 % of the oil can be recovered using natural deletion. Further improve of oil recovery of tight oil reservoir can be achieved by Appling miscible gas flooding process. This paper shows the feasibility of Appling miscible gas flooding as a method of enhancing oil recovery of tight oil reservoirs. The results of this compositional study show that the recovery factor of horizontal well with hydraulic fracture improved to about 30 % when the miscible gas displacement process was applied. Furthermore, the study shows the effect of the minimum miscible pressure (MMP) and the total gas injection volume on the gas flooding process.