Hamoud Al-Anazi

A Successful Methanol Treatment in a Gas-Condensate Reservoir: Field Application

A field test was conducted to investigate the effectiveness of methanol as a solvent for removing condensate banks that form when pressure in the near wellbore region falls below the dewpoint. Core flood experiments on Texas Cream Limestone and Berea cores show that condensate accumulation can cause a severe decline in gas relative permeability, especially in the presence of high water saturation. This can result in well productivity declining by a factor of 3 to 5 as bottom hole pressure declines below the dewpoint. PVT analysis performed on field samples taken from the Hatter’s Pond field in Alabama indicate retrograde condensate behavior. These high-temperature deep gas wells show low gas productivity and large skin. A preliminary analysis of the data indicated the possibility of condensate and water blocking due to the loss of water-based drilling fluids. Core samples were used to measure gas relative permeability. Compatibility tests were conducted to ensure that the injection of filtrate and methanol did not cause any damage to the core. Since the formation brine is very saline, tests were conducted to check for salt precipitation during methanol injection. Based on these laboratory results and a single-well numerical simulation, a field test was conducted. The well chosen for treatment was producing 250 MSCFPD with 87 BPD of condensate. A thousand barrels of methanol was pumped down the tubing at a rate of 5 to 8 B/min. Gas production increased by a factor of 3 initially and stabilized at about 500 MSCFPD. Condensate production doubled to 157 BPD. The well shows a skin of –1.9 after methanol treatment. The increase in gas and condensate production was observed to persist more than 10 months after the treatment. Several possible explanations are provided for the positive results obtained in this test. Some general conclusions are made for the design for future treatments. Introduction Gas production from reservoirs having a bottom hole flowing pressure below the dewpoint pressure results in an accumulation of a liquid hydrocarbon near the wells. This condensate accumulation, sometimes called condensate blocking, reduces the gas relative permeability and thus the wells productivity. Condensate saturations near the well can reach as high as 50-60% under pseudo steady-state flow of gas and condensate. Even when the gas is very lean, such as in the Arun field with a maximum liquid drop out of 1.1%, condensate blocking can cause a large decline in well productivity. The Cal Canal field in California showed a very poor recovery of 10% of the original gas-in-place because of the dual effect of condensate blocking and high water saturation. Several methods have been proposed to restore gas production rates after a decline due to condensate and/or water blocking. Gas cycling has been used to maintain reservoir pressure above the dewpoint. Injection of dry gas into a retrograde gas-condensate reservoir vaporizes condensate and increases its dewpoint pressure. Injection of propane was experimentally found to decrease the dewpoint and vaporize condensate more efficiently than carbon dioxide. Hydraulic fracturing has been used to enhance gas productivity, but is not always feasible or cost-effective. Inducing hydraulic fractures into the formation can increase the bottom hole pressure. Hydraulic fracturing successfully restored the gas productivity of a well that died after the flowing bottom hole pressure dropped below the dewpoint. Recently, a new strategy of using solvents was developed to increase gas relative permeability reduced by condensate and water blocking. Al-Anazi et al. found that methanol was effective in removing both condensate and water and restored gas productivity in both low-permeability limestone cores and high-permeability sandstone cores. Gas productivity decreased about the same extent in both low and high permeability cores due to condensate blocking. After methanol treatment, an enhanced flow period is observed in both low and high permeability cores. Condensate accumulation is delayed for a certain time. During this time, the productivity index is increased an order of magnitude in both low and high permeability cores. The duration of the enhanced flow period is controlled by the volume of methanol injected and its rate of mass transfer into the flowing gas phase after treatment. Methanol treatments remove both water and

Success Criteria for Multistage Fracturing of Tight Gas in Saudi Arabia

The purpose of open hole multistage fracturing (MSF) is to improve hydrocarbon production and recovery in moderate to tight reservoirs. To date, 17 open hole MSF systems have been installed in deep gas carbonate and sandstone wells in Saudi Arabia. Of these, 16 installations have been stimulated (acid or proppant fractured) and flowed back 1 . Overall, the production results from the use of open hole multistage systems deployed in the Southern Area gas fields have been very positive with some variation – most of the wells responded positively and are excellent producers (>20 million standard cubic feet per day (MMscfd)); some showed average results of 8-12 MMscfd; and a few, completed in a tight reservoir, produced at relatively low rates, <3 MMscfd, and did not carry enough wellhead pressure to be connected to the production grid. This article explores the factors that impact the success of open hole multistage completion systems. Some important factors include the type of open hole multistage system used, formation properties, completion liner size, packer type, number and size of stimulation stages, treatment type, well azimuth and fluids pumped. Conclusions are drawn based on careful data analysis to confirm the best practice for successful open hole multistage deployment and conducting effective fracture treatment. This article uses extensive field data and correlates factors to show the applicability of open hole MSF technology. Analysis will cover pre- and post-stimulation data showing the results from the treatments. This analysis will show the factors that contribute to the successful deployment of the completion system, the achievement of higher production rates, and the choice of the right candidates to obtain positive results from the treatment. This article will also show that while the various well and reservoir characteristics have a significant influence on overall well productivity, the completion type is critical and plays a central role in the success of the stimulation treatment and final production levels. Open hole multistage systems have been deployed

A Successful Methanol Treatment in a Gas/condensate Reservoir: Field Application

A field test was conducted to investigate the effectiveness of methanol as a solvent for removing condensate banks that form when pressure in the near wellbore region falls below the dewpoint. Core flood experiments on Texas Cream Limestone and Berea cores show that condensate accumulation can cause a severe decline in gas relative permeability, especially in the presence of high water saturation. This can result in well productivity declining by a factor of 3 to 5 as bottom hole pressure declines below the dewpoint. PVT analysis performed on field samples taken from the Hatter’s Pond field in Alabama indicate retrograde condensate behavior. These high-temperature deep gas wells show low gas productivity and large skin. A preliminary analysis of the data indicated the possibility of condensate and water blocking due to the loss of water-based drilling fluids. Core samples were used to measure gas relative permeability. Compatibility tests were conducted to ensure that the injection of filtrate and methanol did not cause any damage to the core. Since the formation brine is very saline, tests were conducted to check for salt precipitation during methanol injection. Based on these laboratory results and a single-well numerical simulation, a field test was conducted. The well chosen for treatment was producing 250 MSCFPD with 87 BPD of condensate. A thousand barrels of methanol was pumped down the tubing at a rate of 5 to 8 B/min. Gas production increased by a factor of 3 initially and stabilized at about 500 MSCFPD. Condensate production doubled to 157 BPD. The well shows a skin of –1.9 after methanol treatment. The increase in gas and condensate production was observed to persist more than 10 months after the treatment. Several possible explanations are provided for the positive results obtained in this test. Some general conclusions are made for the design for future treatments. Introduction Gas production from reservoirs having a bottom hole flowing pressure below the dewpoint pressure results in an accumulation of a liquid hydrocarbon near the wells. This condensate accumulation, sometimes called condensate blocking, reduces the gas relative permeability and thus the wells productivity. Condensate saturations near the well can reach as high as 50-60% under pseudo steady-state flow of gas and condensate. Even when the gas is very lean, such as in the Arun field with a maximum liquid drop out of 1.1%, condensate blocking can cause a large decline in well productivity. The Cal Canal field in California showed a very poor recovery of 10% of the original gas-in-place because of the dual effect of condensate blocking and high water saturation. Several methods have been proposed to restore gas production rates after a decline due to condensate and/or water blocking. Gas cycling has been used to maintain reservoir pressure above the dewpoint. Injection of dry gas into a retrograde gas-condensate reservoir vaporizes condensate and increases its dewpoint pressure. Injection of propane was experimentally found to decrease the dewpoint and vaporize condensate more efficiently than carbon dioxide. Hydraulic fracturing has been used to enhance gas productivity, but is not always feasible or cost-effective. Inducing hydraulic fractures into the formation can increase the bottom hole pressure. Hydraulic fracturing successfully restored the gas productivity of a well that died after the flowing bottom hole pressure dropped below the dewpoint. Recently, a new strategy of using solvents was developed to increase gas relative permeability reduced by condensate and water blocking. Al-Anazi et al. found that methanol was effective in removing both condensate and water and restored gas productivity in both low-permeability limestone cores and high-permeability sandstone cores. Gas productivity decreased about the same extent in both low and high permeability cores due to condensate blocking. After methanol treatment, an enhanced flow period is observed in both low and high permeability cores. Condensate accumulation is delayed for a certain time. During this time, the productivity index is increased an order of magnitude in both low and high permeability cores. The duration of the enhanced flow period is controlled by the volume of methanol injected and its rate of mass transfer into the flowing gas phase after treatment. Methanol treatments remove both water and

Optimum Mud Overbalance and ROP Limits for Managing Wellbore Stability in Horizontal Wells in a Carbonate Gas Reservoir

larger stress contrast across the wellbore resulting from the overburden (S v) and difficulties with drilling in the maximum horizontal stress (S Hmax ) direction under the prevailing strike slip stress conditions in the field 1 . Several data sets, including open hole logs, were integrated through geomechanical analy ses 2 to develop a mechanical earth model (MEM) providing magnitudes of the three principal in situ stresses, the azimuth of S Hmax direction, pore pressure and the rock strength proper ties along the logged open hole section. Horizontal in situ stresses can be calculated using a poroelastic horizontal strain model 3 and further calibrated by the observed wellbore wall failure; the result is continuous profiles of stress magnitudes along the well trajectory, Fig. 1. Apart from pore pressure, the magnitudes of horizontal Saudi Aramco has been drilling horizontal and multilateral wells to develop gas fields. Due to a production-induced drop in reservoir pressures, along with the tight nature of the reser voir rock, development activities have focused more on placing new wells, completed with multistage hydraulic fracturing, to ward the minimum horizontal stress (S Hmin ) direction with the goal to improve lateral reservoir contact, which enables higher production at sustained rates, thereby increasing recovery while drilling fewer wells. Horizontal wells drilled in the S Hmin direction are made more challenging by complex geological conditions and com pressional in situ stress conditions. The data shows that some wells were drilled without major difficulty while other wells encountered more problems, leading to stuck pipe events. A detailed study was conducted to identify the nature of these problems and ascertain major controlling factors for this variable drilling experience. The goal was to make future operations safer and more efficient through recommendations based on a diagnostic analysis of the observed problems in existing wells. Analysis of data suggests that excessive borehole breakouts and a faster rate of penetration (ROP) are the key contributing factors to the observed drilling challenges. In addition, differ ential sticking has been found to be a potential risk across high porosity and/or depleted zones. As a result, determining the optimum mud weight for a given well based on a pre-drill geo mechanics model was recommended to manage the hole stability. In addition, a safe limit for the ROP, set as a function of hole azimuth, was identified to manage efficient hole cleaning and avoid stuck pipe issues due to pack off. The recommendations made based on this analysis enabled successful drilling and timely completion of several horizontal wells across the field.

Evaluation of a pH-sensitive polymer for gravel-packing operations

Rheological data is presented for a type of polyacrylic acid polymer as a function of polymer concentration, pH, shear rate, and temperature. It was found that the viscosity of the polymer is strongly dependent on the pH of the solution. Compatibility tests showed that the polymer was compatible with most brines (NaCI, NH 4 Cl, and KCl) used for field applications. Core-flow results indicated that the filtration rate was low compared to that of hydroxethylcellusose (HEC). Our evaluation study shows that this anionic polymer would be an excellent nondamaging carrier fluid for gravel packing. It has excellent rheological and suspension properties and is easily broken down with a mild acid wash before flowback.

Explaining Anomalous Wellbore Instability Problems in Ghawar Khuff Reservoir

Explaining Anomalous Wellbore Instability Problems in Ghawar Khuff Reservoir Khan, Khaqan; Abdul Halim, Ab Hamid and Anazi, Hamoud Abstract Saudi Aramco is aggressively pursuing drilling horizontal and multilateral wells in Khuff and Pre-Khuff reservoirs in the Ghawar Field to enhance gas production. Due to production-induced decreasing reservoir pressures coupled with tight nature of the reservoir rock, majority of the new wells are attempted in the minimum horizontal stress direction and completed with multistage hydraulic fracturing treatments which provide improved lateral reservoir contact enabling higher production at sustained rates as well as help increase recovery with lesser number of wells. However, horizontal wells drilled in the minimum horizontal stress direction are somewhat more challenging due to prevailing stress conditions resulting from regional tectonic compression. The experience to date shows that some wells were drilled without major drilling difficulty while some other wells have experienced more drilling problems leading to severe stuck pipe events and tools lost in hole. As wellbore instability can result from a combination of geomechanics and drilling-related factors, a detailed study was performed to identify the nature of these problems and ascertain major controlling factors for this variable drilling experience to make future drilling operations safer and more efficient through recommendations based on a diagnostic analysis of the drilling problems in existing wells. Analysis of data suggests that borehole ovality (breakouts severity) is a key contributor to the drilling challenges but it is not the only cause of the difficulties experienced. Apart from bore hole ovality, rate of penetration (ROP), hole cleaning and tripping practices also play significant roles in the drilling process (Fig. 1). The study also indicates that borehole ovality varies spatially suggesting variable stress conditions in the field resulting from the interaction of tectonic compressions, rock heterogeneity, reservoir depletion and structural geometry. Based on understanding of geomechanics, stable mud weight window was identified to manage breakouts and differential sticking problems. The implementation of these findings helped to drill wells safely and achieving the planned target reservoir contact and rate.