Subsea Chemical Injection Pump. an Intensive Qualification Program

We generate a microwave discharge nitrogen plasma using a rectangular waveguide and a quartz tube (30 mm i.d.) inserted along the vector of the electric field, with an adjustable short-circuited plunger. The typical discharge conditions used are as follows: microwave frequency 2.45 GHz, input power 550 W, nitrogen (99.5%) gas flow rate 0.01–1.6 l/min, and discharge pressure p=0.5–10 Torr. Electron temperature Te, and density ne are measured using a double probe. Vibrational temperature Tv is obtained from the population density of the vibrational exited states of N2 C 3Πu by spectroscopic examination. Rotational temperature Tr is obtained from a comparison of the rovibronic spectra observed experimentally with the calculated ones. It is found that Te≃0.5–2 eV, Tv≃0.45–1 eV, and Tr≃0.06–0.1 eV under the present pressure conditions, whereas ne≃1011–1012 cm-3 at a low discharge pressure, and ne≃108–109 cm-3 at a high discharge pressure. We discuss the measured vibrational populations by theoretical calculations in which the variation in their number density is expressed in terms of molecular processes in the nitrogen plasma.

Barrel style centrifugal compressors are widely used for high pressure gas compression applications in the oil and gas industry. Using a modular rotor in a high pressure centrifugal compressor for Oil and Gas Service is a method that is distinctly different from ubiquitous solid shaft machine designs. It is accepted in the governing standards, for example API 617, and allows for significant flexibility under changing operating requirements. Using a modular rotor allows to avoid splitting diaphragms, but it also requires different assembly, balancing and test methods. The machine described in this study is a single compartment compressor capable of 340 bar discharge pressure. The study provides aerodynamic test data for a series of closed loop tests at discharge pressures of over 220 bar, using Nitrogen, CO2 and natural gas as test gases, to validate compressor performance, rotordynamic stability and mechanical integrity. An important feature of the test campaign is the detailed evaluation of the transient behavior during tests to verify the machine integrity at rapid shutdowns at high discharge pressures. The paper also discusses the applications for such centrifugal compressors in the oil and gas industry, considerations on standardized designs, and its integration in a modular design system.

Coiled tubing drilling technology is gaining popularity and momentum as a significant and reliable method of drilling horizontal underbalanced wells, and is quickly moving into new frontiers. To this point, most efforts in the Western Canadian Basin have been focused towards sweet oil reservoirs in the 900 – 1300 metre (3000 – 4300 feet) true vertical depth range, however there is an ever-increasing interest in gas-producing formations. Figure 1 shows a composite vertical section of the horizontal or directional underbalanced wells drilled with coiled tubing in Canada, and also highlights the aforementioned trend towards oil over gas. Significant design challenges on both conventional and coiled tubing drilling operations are imposed when attempting to drill these formations underbalanced. Coiled tubing is an ideal technology for underbalanced drilling due to its absence of drillstring connections resulting in continuous underbalanced capabilities, as well as its suitability for sour well drilling and live well intervention without surface releases of reservoir gas. Through the use of pressure deployment procedures it is possible to complete the drilling operation without need to kill the well, thereby maintaining underbalanced conditions right through to the production phase. The use of coiled tubing also provides the means for continuous wireline communication with downhole steering, logging and pressure recording devices. Coiled tubing drilling rigs currently exist in several different forms and setups, but generally consist of a drilling coil, injector to feed the tubing into or out of the well, BOP system for well control and return fluid path, and a control cab and power unit. The coiled tubing drilling equipment used to drill the case studies presented later in this paper consisted of either 60.3mm or 73.0mm (2.375 or 2.875 inch) coiled tubing and injector with a hydraulic power unit with control cabin and accumulator. A coiled tubing hybrid mast unit and substructure complete with V-door, catwalk and pipe racks was used. Pumping equipment included a fluid pumper capable of liquid rates of 0.10-1.5 m3/min (0.6 – 10 barrels per minute), nitrogen pumper capable of 10-120 m3/min (350 – 4250 standard cubic feet per minute), and a nitrogen bulk storage unit of 50,000 m3 (1.8 million standard cubic feet) capacity. When drilling sour gas formations, a chemical injection pump for corrosion inhibition may be used.

The relative densities of SiCln (n = 0–2) in SiCl4 radio frequency (rf) glow discharge plasma are measured by mass spectrometry. The effects of discharge parameters, i.e., rf power, discharge pressure, substrate temperature, and SiCl4 flow rate on the relative densities of SiCln (n = 0–2) are investigated in detail. An optimum configuration of discharge parameters (low rf power, high discharge pressure, low substrate temperature, and low flow rate), which enhanced the formation of SiCln (n = 0–2) radicals, is searched by a great deal of measurements and discussions. In the optimum configuration of discharge parameters, we measure the spatial distribution of SiCln (n = 0–2) radicals in the most optimized plasma parameters. The experimental results reveal that Si and SiCl may be the dominant precursors in forming the thin film.

Typically, the concentration of corrosion inhibitor levels in field fluids is routinely monitored. Understanding the level of corrosion inhibitor can provide information on the correct functioning of chemical injection pumps as well as determine the effects of changing system conditions, such as water cut or solids production, on chemical availability. Yet, despite the value of monitoring, the residual methods available to operators are often not sufficiently reliable or are too complex to apply in the field. A corrosion inhibitor micelle-detecting technique offers an alternative approach. A significant body of work can be found in the literature regarding the formation of micelles in model fluids and for single chemical species. The relevance of the approach for the significantly more complex field fluids and commercial corrosion inhibitor formulations is shown and discussed.

Laboratory evaluation of nitrogen injection for enhanced oil recovery: Effects of pressure and induced fractures

Reservoir testing is always needed to understand flow potential and to confirm hydrocarbon discoveries. In Southeast Asia, reservoirs are frequently laminated, thinly bedded, and compartmentalized. Testing every individual (main) zone with Drill Stem Test (DST) is not economical due to cost and rig time constraints. Different testing methods have been used such as Tubing Stem Testing (TST) and multi zone DST, with and without Production Logging Tool (PLT) for zonal contribution. However, these methods still need to flow hydrocarbon to surface, require a large footprint, i.e. separator units at surface, and to flare hydrocarbon to atmosphere. Interval Pressure Transient Test (IPTT) and Deep Transient Testing (DTT) have been introduced as greener alternative wireline testing methods, where each zone can be isolated and tested individually without flaring. IPTT has been used for more than 20 years to derive zonal permeability. IPTT tests single hydraulically connected layers and obtained permeability often compares well to testing derived permeability. However, IPTT feasibility is limited in combinations of permeability, thickness and reservoir fluid viscosity. With the introduction of DTT, the use of a circulating sub has enabled much larger volumes with longer period without jeopardizing well stability. With higher flowrates and improved gauge resolution, a much deeper radius of investigation can be achieved with this green testing technology, and higher permeability gas reservoir testing is feasible. This paper will show examples where DST with either IPTT or DTT have been acquired on the same well. In each case, an integrated workflow for log-to-reservoir scale model is constructed from formation testing data and high-resolution logs, which is used to generate a zonal inflow performance relationship (IPR). In the first example, a cased hole DTT was acquired in a good permeability gas reservoir, and the integrated workflow was used to derive zonal IPR and minimum connected volume. In a second well, an IPTT was conducted after quality fluid samples were acquired which was followed by a commingle DST. The IPTT is used to derive individual layer permeability within the DST interval and to characterize zonal contributions. This is of critical importance for the production and reservoir recovery strategy in this multi-zone reservoir. In the third example, both DTT and DST were run in a high-permeability gas reservoir. Results are compared in terms of fluid sampling and pressure transient data. An integrated workflow was used to upscale the DTT calibrated model to the DST zones. In this example, even with a small DTT drawdown, the pressure transient from high-resolution gauges allowed for valid transient data. This paper shows a comparison of DTT to DST in a high- and low-permeability gas reservoir together with the discussion of test selection implications such as footprint, CO2 emissions, interpretation techniques together with lessons learned and best practices.

Summary This paper reviews the planning and implementation of a flow test of a gas reservoir, including the general goal of the test, equipment used, problems anticipated, and the steps to minimize or to avoid problems. The well successfully tested at rates of 22.5 MMcf/D and 2,670 B/D condensate with a 2,800-psi flowing tubing pressure through a 46/64-in. choke for 4 days. Introduction The test of Viosca Knoll Block 957 Well No. 1 Sidetrack No. 2 was Amoco Production Co.'s deepest test from a floating rig. Viosca Knoll 957 is 115 miles southeast of New Orleans in 3,500 ft of water. The test, at a record water depth for the Gulf of Mexico, also set a world water-depth record for testing a gas reservoir. Safety to crew and the environment were top priorities during the planning. A team consisting of drilling, completion, reservoir, and facilities engineers and a foreman were assigned to plan and implement the test. Early planning involved field, service company, and engineering groups. Every effort was made to identify potential problems and to design the system to handle them. The goals of the test were to determine reservoir properties and reservoir limits. Several significant challenges were involved in the well test. The reservoir was gas with a potentially significant condensate yield. The ability to dispose of the large volumes of produced fluids safely without polluting was critical to maintaining uninterrupted flow. Potential shut-in surface pressure was 6,500 psi. Seafloor temperature in 3,500 ft of water was 39F. Preventing gas hydrates was a major problem. The inhibition was Preventing gas hydrates was a major problem. The inhibition was done by chemical injection into the flow stream before the gas and condensate reached ambient seafloor temperature. The ability to acidize was necessary. Optimum reservoir evaluation required varying the lengths and rates of the flow periods and shut-in times. During startup, hydrate inhibition was critical and a large volume of fluids in the surface tanks, both the tubing volume and produced fluids, required significant handling and proper disposal. produced fluids, required significant handling and proper disposal. The well tested was the third sidetrack from a wellbore spudded in Jan. 1989 by the drillship Discoverer 534. Initial plans were to test the second sidetrack from the drillship in the spring, but a third sidetrack was added to the drilling program and the drilling was prolonged into the summer. Rather than begin testing operations in July, a decision was made to move the drillship off location and to bring back the ship or another rig after hurricane season. The time required to secure the ship for a hurricane when in the testing mode would require beginning to secure when the potential storm was at least 750 miles away (mid-Cuba). This was not considered practical; therefore, Penrod 78 was moved to location in late October after Hurricane Penrod 78 was moved to location in late October after Hurricane Jerry.

In gas reservoirs, the well production can be reduced due to the development and accumulation of condensate in the near-wellbore zone. Various techniques are used to minimize the condensate damage and maintain hydrocarbon production. Hydraulic fracturing and wettability alteration techniques are the most effective methods. However, these techniques are expensive, especially in deep gas reservoirs. This paper introduces a new approach for mitigating condensate accumulation by integrating the hydraulic fracturing and wettability alteration treatments. The efficiency of two chemicals that can generate multiple fractures and alter the fracture surfaces to less condensate status is investigated in this work. Thermochemical fluids and chelating agent solutions are used to mitigate the condensate damage and improve gas production for the long term. Several laboratory measurements were carried out to study the performance of the proposed approach; coreflooding, zeta potential, and nuclear magnetic resonance (NMR) experiments were conducted. The chemicals were injected into the tight rocks to recover the condensate and improve the flow conductivity. Zeta potential was performed to assess the rock wettability before and after the chemical injection. Moreover, the changes in pores network due to the chemical treatments as analyzed using the NMR technique. Thermochemical treatment removed around 66% of the condensate liquid, while the chelating agent reduced the condensate saturation by around 80%. The main mechanism for condensate removal during thermochemical flooding is the generation of micro-fractures that increase the rock permeability and improve the condensate flow. On the other hand, chelating agents can alter the rock wettability toward less oil-state, leading to considerable recovery of the condensate liquid utilizing a wettability alteration mechanism. Finally, an integrated approach is suggested to injecting thermochemical fluids followed by chelating agent solutions. The proposed technique can lead to generating micro-fractures of less oil-wet surfaces, consequently, the condensate bank can be removed by more than 90%.

We have become accustomed to looking for gas in reservoirs that have good porosity and permeability, so that we may produce at high flow rates. What is the meaning, then, of the new search for "tight gas" reservoirs with low porosity and low permeability that is so captivating exploration? The reason for investor interest in "tight gas" is that these peculiar reservoirs do not need expensive search tools, have little dry hole risk, and have enormous lateral extent. "Tight gas" accumulations often occur over hundreds of square miles. These "tight gas" reservoirs appear to contain enormous quantities of gas that are challenging our engineering talents to extract profitably. These "tight gas" reservoirs are not merely poor quality conventional reservoirs, but have a number of unique characteristics that require new exploration and production techniques to be employed to efficiently find and develop the gas. These "tight gas" reservoirs require juxstaposition with a gas-expelling source rock, and to be discontinuous, at the reservoir level.

Enhancing the energy efficiency of land vehicles air conditioning units through a new evaporative membrane cooler

ADNOC Onshore is operating Habshan gas production field on behalf of Abu Dhabi National Oil Company (ADNOC). The gas reservoir production zones were developed under different project phases. The field has 250 gas (production and injection) wells, which are placed and located in approximately 1200 square kilometers. All gas wells are designed to have SCADA system to monitor, operate and control the wellhead control systems. Current practice within ADNOC Onshore is to carry out monitoring for Cathodic Protection (CP) of well casing and Chemical Injection (CI) surveys on quarterly basis, this is carried out by mobilizing entire crews physically (visiting every single location) and reporting findings/conditions in order to carry out preventive maintenance and necessary repairs. The aim of the project is to establish a remote monitoring system utilizing the existing Supervisory Control and Data Acquisition (SCADA) setup in order to monitor the applied corrosion controls, CP and CI injection systems. Based on the implemented modification, essential information was collected, intensive review and analysis were performed and revealed that the system is functioning perfectly as per the operation's requirement for both (CP & CI). This approach forms a vital aspect of the integrity management of the asset by monitoring the effectiveness of the applied corrosion controls, in addition, the implementation will help Operations to optimize resources, efficiently monitor, maintain, and ensure safety of the facilities and its integrity. Moreover, the implemented method will drastically reduce the associated travelling risk, limiting exposure to the harsh environment (Desert) and potential cost saving.

Radial jet drilling technology is an economic and efficient method to enhance oil and gas recovery by drilling several lateral micro-holes from a vertical main borehole. The micro-holes drilled by high-pressure hydraulic energy can improve the contact area between wellbore and reservoir. The maximum extended reach of lateral micro-hole is a key parameter to evaluate the effect of radial jet drilling as the production increases with the length of lateral holes. However, the maximum extended reach of radial jet drilling reported has not been studied adequately. In this paper, we have established a new model which combines hydraulic friction and mechanical friction to analyze the extended reach of radial jet drilling. The results show that the flow rate is a main influence factor affecting the flexible hose extended reach which increases with the growth of flow rate. The outlet angle of deflector has a great effect on the extended reach especially at high flow rate, while the turning angle has little effect on extended reach. This work provides a systematic method including hydraulic and deflector optimization for the design of radial jet drilling to help develop the adjacent satellite oil & gas reservoirs.

Tight gas reservoirs exhibit frequently long periods of transit flow regime and do not reach the Boundary Dominated Flow (BDF) across their production history. This is caused due to low matrix permeability, that creates the need of a pervasive fracture networks to maximize the well – reservoir contact and drainage area. This will unlock high initial flow rates and a sharp decline from the early years of production. The development of new empirical equations approached to the understanding of tight gas reservoirs variability, through declination parameters. However, this produces uncertainties since the empirical models could have an analytical theory that has not been demonstrated at that time. The role of uncertainty analysis is very crucial throughout the investigation of the reservoirs Tight Gas, especially when production profiles present an unknown behavior in later periods. In this case, the degree of uncertainty increases, so the need for a probabilistic analysis to forecast production is fundamental. The paper proposes a methodology to define the statistical distribution of the declination parameters and predicts the behavior of gas reservoirs Tight, taking into account the uncertainties. The method also allows calculating a wide range of realization for each production well, sampling randomly the input parameters from the statistical distributions as in a Standard Monte Carlo Workflow. We provide an Evaluation of the realibility of the methodology considering a wide range of predictions and an evaluation of the Results with an avaiable historical dataset. To finally estimate reserves in terms of P10, P50 y P90 based on a combination of Advanced Decline curve [1] at specific time limit or abandonment rate. This case study was developed on a sectorial block of the Lajas Formation of the Neuquen Basin, with wells in production, where the use the uncertainty assessed to define the development strategy for a new field and the project choices. [1] Stretched Exponential Production Decline Model(SE), Doung Model(DNG), Power Law Exponential Method, Modified Hyperbolic and Modified Doung.

Skin is the most challenging problem in oil and gas production resulting from near wellbore mechanical damage or non-Darcy effect due to gas turbulence. Mechanical skin is introduced to the pay zone during drilling and completion phase while rate-dependent skin (non-Darcy effect) comes into play as gas production commences. Also turbulence effect may cause a huge pressure drop for oil wells but it is more sensitive in gas production. Rate-dependent skin is caused by contravening basic Darcy's assumptions in gas reservoir and would be sensible as gas starts rushing to the wellbore. It can be used to have an idea about fluid compressibility and flow path tortuosity near wellbore caused by high gas flow rate. Lots of attempts have been directed for computation of rate-dependent skin. Most of them proposed a power mode equation for estimation of non-mechanical skin in gas reservoirs. This includes turbulence coefficient, squared drawdown pressure, flow rate, and deviation coefficient. The turbulence coefficient (D) to be determined needs running a gas well test or at least two pressure flow rate data points. Other conventional methods also can be used for prediction of this parameter. But as a matter of fact, every predictor model may ignore some effective parameters for simplicity, which might deviate the result from reality. Thus, using a better approach including as much as possible effective parameters such as artificial intelligence can result in more accurate results. The authors propose a new technique to estimate value of the turbulence coefficient (D) by using neural networks based on skin factor, reservoir rock, and fluid properties. It is easy to apply and evaluate. The proposed method is validated using field data under variety of conditions. A computed value of D from neural network matches real data pretty well in comparison with conventional correlations.