Beam Pumping System Efficiency Improvement

In Agiba’sWesternDesert Fields

By

Luca Ponteggia (Agiba Petroleum company)

M. Ghareeb, Artificial Lift Expert, LufkinMiddle East

Abstract:

Beam pumping systems were introduced in the Meleiha oil fields in 1986 as the most suitable means of artificial lift. Initially low running lives were reported, but continuous improvement efforts have increased them significantly. Improvement included surface and subsurface equipment (re-sizing, modification, monitoring, completion, analysis, handling, & operating procedures).

This study will cover the operational performance of the sucker rod system, the experience gained through its application with problem analysis, and solutions adopted throughout 19 years of operation to optimize the system efficiency.

1- Introduction

Western desert fields have more than 104 oil producing wells with an average of +/- 57,000 BFPD (+/-31,000 BOPD) distributed over five main fields. All wells are artificially lifted except for one is flowing and sucker rod pumping is the main lifting system. Figure-1 shows the distribution of the different artificial lift methods.

Figure-1: Different production systems for Agiba’s W. D. Fields

The productive zones are mainly concentrated in the Baharia formation where there is a sequence of oil bearing zones. Figure-2 is a location map showing Agiba’s operating areas.

Figure-2: location map

Agiba production began in December 1984 by using temporary production facilities and crude was transported to the Elhamra terminal by trucks. In November 1986 permanent facilities were commissioned and crude was transported to Elhamra through a 16-inch pipe line (166 km). Figure-3 shows the production history of the Western desert fields. Sucker rod systems were introduced at that time in the Meleiha oil fields as the most suitable means of artificial lift.

Figure-3 shows the production history of Western desert fields

Initially, very low running lives were reported for subsurface equipment. Continuous efforts by monitoring and analyzing the failures, in addition to the introduction of technology, overcame most of the problems and extended pump efficiency and running life. Well performance was analyzed by using computerized dynamometer and echo-sounding tools. Furthermore, some performance curves were developed in-house to assist in predicting well production rates from wellhead temperatures, which allow for troubleshooting.

2- System Design

2.1 Initial production

Table (1) shows the initial reservoir data and fluid properties for the Meleiha fields. The sucker rod system design was introduced to provide maximum possible production in a depletion drive reservoir (fast decline in reservoir pressure with production).

Table 1 Initial reservoir and fluid proprieties

Res Press. psi / Res. Temp
oF / visc.
cp / Pb,
psia / Bo,
rb/stb / Rs, scf/stb / API
MW / 2250 / 195 / 0.85 / 450 / 1.125 / 250 / 38
Aman / 2300 / 196 / 0.8 / 240 / 1.175 / 100 / 40
NE / 2250 / 193 / 0.8 / 480 / 1.26 / 210 / 40
SE / 2350 / 198 / 0.4 / 1170 / 1.6 / 790 / 42

2.1.1 Surface and subsurface equipment sizing

In 1986 all the Meleiha fields were almost virgin and they showed the capability to produce +/- 1000 BFPD per well. Therefore the equipment was selected based on 1000 BFPD as the target production rate. Based on wells productivities and bottom hole conditions the pumps setting depths were chosen to be +/-5000 ft. Technical and economical studies performed at that time showed that class III surface pumping units were the most efficient means of artificial lift. The goal was to minimize using workover rigs to pull and run tubing in case of any problems with the subsurface pump, therefore insert type pumps were chosen. A tapered (86) High tensile strength (140,000 to 150,000 Ib) rod string was the best selection. Ultra high slip motors were installed on all Meleiha units and have gained wide acceptance as the prime mover of choice. The motor has four torque modes to generate different amounts of slip and is also equipped with a timer, which allows the user to adjust the pumping time according to the wells capability.

Table (2) Initial surface and subsurface equipment

Item / Size / Type
D . H. P. / 30-250-RWBC- 24- 4 / RWBC
Rod string / (86) 41.2 % * 1”
40.2 % * 7/8” 18.6 % * 3/4” / High tensile strength
(140,000 to 150,000 Ib)
Rod coup. / Standard size / Class T
Tubing / 3.5 “ * 9.3 Ib/ft
Surface unit / M - 912 D - 365 - 144 / Mark-II
Prime mover / 75 HP / Electrical ultra high slip

2.1.2 Well completion design

Figure-4 shows the main completion design where the wells are equipped with 3 1/2 inch tubing. The tubing is anchored to 7 inch casing with a mechanical anchor catcher and is kept in tension with 15,000 Ibs of over pull (Figure 4a). The pump is seated in a 2.75 inch seating nipple and most of the wells have the described completion except some that may produce from two different zones. In these wells the anchor catcher is replaced by a packer for a selective completion system. (Figure-4b).

Figure-4: sucker rod well completions

3-System performance and evaluation

Initially very low equipment running lives were reported. Rod parting combined with down hole pump problems represented the highest percentage of failures. Rod parting was mainly concentrated in the upper part of the 7/8” and 3/4“ strings. All the failures reported were fatigue or rod parting due to unscrewing of the coupling. Down hole pump problems were mainly due to valve leaks (travelling and standing), pump connection unscrewing or pump sticking. Sucker rod parts and pump failures can be easily repaired in a reasonable time by pulling and running a rod string or pump after replacing or repairing the damaged one. But when a stuck pump is found, workovers are the only remedial job that can be applied. A workover rig is much more expensive compared with a pulling unit and the well down time has a bigger impact on the production level. Stuck pump problems dramatically increased in the Meleiha field which affected the production performances and the cost per barrel.

After root cause failure analysis the main factors affecting the equipment performances were highlighted:

a- The reservoir is a depletion drive type and the fast decline in reservoir pressure was affecting the pump intake pressure. Therefore, the gas and fluid pounding problem became a serious issue and the decrease in the dynamic fluid level consequently increased the peak polished rod load due to increasing the net lift.

b- The use of one size and type of down hole pump reduced the ability to match pump production with the wells capability. Even after reducing the surface pumping parameters (stroke length and strokes per minute) to a minimum.

c- Since all pumps were bottom hole down type, pump sticking increased due to sand and debris in the fluid.

d- Lack of experience with sucker rod pumping was affecting the failure analysis.

e- Mishandling of high tensile strength rods caused sucker rod failures.

f- Bad fluid data due to out of date technology.

3.1 Failure analyses

Figure-5 shows the distribution of typical failures in sucker rod installations in the Western desert fields. Failures are divided into four major categories, which are:

  1. Sucker Rod and polished rod failures
  2. Down hole pump failures.
  3. Tubing wear.
  4. Surface Unit Failures

Figure-5: Typical failure in sucker rod installations in W.D fields

3.1.1 Sucker rod failure analysis

The rod string used in the beginning was an API 86 (18.6 % of 3/4”, 40.2 % of 7/8" and 41.2 % of 1"). Due to fluid/gas pound, and improper handling & store, rod parting frequently occur, in the top of the 7/8" and 3/4" rods. As mentioned earlier, due to the fast decline in reservoir pressure and the wells capability to produce the desired production, a time clock was introduced. This also caused an increase in the frequency of rod parting. Due to the timer the rod string transferred from static (well off) to dynamic conditions with a full load (well on) every 18 minutes or 72 times a day. Another important cause of rod parting was the handling. This type of rod if damaged, can easily loose it’s high strength properties, in fact all the failures reported were fatigue in nature. (Figure-6)


Figure-6: Typical shape of sucker rod failures for W. D wells

3.1.2 Down hole pump failure analysis.

As mentioned before, all the pumps were standardized to be 2.5 " RWBC. So as to handle well production at the time, and minimize spare parts and handling tool requirements.

Due to the fast decline in the reservoir pressure, gas and fluid pounding became a serious problem causing traveling and standing valve damage.

After retrieving the pumps, it was found that either the traveling or standing valve unscrewed. The traveling valve could be dealt with in a short period of time unless it dropped inside the pump, in that case it would require a round trip. In the case of the standing valve, the seating assembly would stay in the seating nipple and need another trip to fish it. Fishing a standing valve usually required additional wire line operations to fish the ball when it unscrewed at its bottom connection. The success of the fishing was not guaranteed and sometimes the well was down for up to four days to recover the standing valve. Well down time was mainly due to pulling /running operations and wire line fishing jobs for standing valves. The situation was improved by putting the well on a timer, dependant on its productivity. In spite of the improvement, another problem appeared during the downtime when sand and debris would settle around the barrel causing a stuck pump. A temporary solution was introduced by scheduling wells that were working on timers, to have the pumps unseated once a month for washing the sand and debris into the rat hole. After the pump was unseated twice, we had to pull it to replace the seating cups.

The other main problem was stuck pumps which existed only in the Bottom Hold-Down type. This BHD creates the possibility of sand & debris accumulating in the dead area between the pump and the tubing wall. Such problems have been overcome by introducing the Top Hold-Down pump (figure 7 shows the two different types). The pump anchor system is used in the following:

1 -To put the wells with tubing leaks back (without a work-over).

2 - To convert the wells without seating nipples to a sucker rod system (without a work-over).

Figure-7: Bottom and top hold-down pump assemblies

3.1.3 Tubing wear failure analysis

The main reason behind tubing wear is the movement of rods and rod couplings within the production string. There is also some movement of the tubing resulting from the pump action which results in wear between the tubing and casing if the tubing is unanchored.

Sucker rod movement inside the tubing, lead to a mutual friction between the rods and tubing which created the tubing wear that grew as a longitudinal crack along the tubing joints. Figure-8 shows an example of tubing wear resulting from this friction.

Figure-8: Example of tubing wear

An investigation was conducted and the conclusion was that all the reported tubing failures had longitudinal cracks with an average length of 10 ft. and all the cracks were in the lower part of the tubing (up to 500 ft above the pump seating nipple). This tubing interval was located against the sinker bar portion of the sucker rod string.

The reason behind this problem has been investigated and summarized as follows:

1-These cracks were created as a result of friction between the sucker rod string and tubing. They are located in the lower portion of the tubing because the tubing string typically buckles at this depth (just above the anchoring point). Buckling in the lower portion above the anchoring position results from the use of a hydraulic or mechanical packer or anchor catcher with insufficient tension.

2-Using 1” sucker rods as a sinker bar with full size couplings, which creates the possibility of friction with the tubing inner wall. (Figure 9 shows relative sizes of sucker rod couplings in 3-1/2 in. tubing with contact area).

3-The high water cut wells were producing free water, which created very poor lubrication and cooling between the sucker rods and tubing.

4-The produced water had a higher thermal coefficient then the oil, so it increased the buckling effect of the tubing.

Figure 9: Relative sizes of sucker rod couplings in 3-1/2 in. tubing

Statistics for tubing leakage over the last 9 years are shown by Figure-10

Figure-10: Number of workover due to tubing leak over the last 9 years

3.2 Gas interference problems

Pumping free gas significantly decreases the beam pumping systems overall efficiency. This directly contributes to higher lifting cost as well as indirectly accelerating the deterioration of surface and subsurface equipment. Consequently, the process of lifting will be economically unfeasible. There are several techniques that can be applied in order to improve the pump efficiency in gassy wells. Pumping below perforations has proved to be the most successful.

Gas interference reduces the volumetric efficiency and in the worst case the well stops pumping due to gas lock.

Mechanical gas separation (down hole gas separator) can help in reducing gas interference by minimizing the quantity of gas entering the pump. Different types of separators are available on the market.

In Agiba applications some of the NE wells, SE, Zarif, Faras and Ramel fields are the highest gas to oil ratio (GOR) wells (over 300 SCF/STB). In 1988 Agiba ran poor-poy type gas separator tests for two of the SE wells (SE-1 and SE2). They did not show any significant improvements and this technique had some limitations:

It was not effective for wells producing over 300 BOPD.

It Impedes possible wire-line operations in the well in which it is used

For pump intake pressure above the bubble point, the gas separator deteriorates total volumetric above the bubble point, the gas separator liberation of gas due to increasing the pressure losses.

Seating the pump or at least the intake below the perforations is the most efficient technique if the well conditions allow for it. In 1998 Agiba with GPC engineers tried and succeeded to run 23 wells below the perforations. The technique helped to bring back some of the GPC wells which it shut in due to high GOR. Two years later, Agiba began to apply the process for some of the Meleiha wells (M-8, SE-6). Since it proved to be very efficient most of the Faras, Raml and Zarif field wells were running below perforations. Application of the technique created the following advantages:

  • Increased pump submergance which resulted in more production.
  • Created a natural gas-separation, which improved the pumps mechanical performance.

There are some limitations to this technique, which is not recommended for sandy wells where pump-sticking problem arise.

3.3 Scale deposition problem

It was observed that scale formation problems started to appear in some of the Meleiha and Raml field wells. Chemical analysis showed that it was the calcium carbonate (CaCO3) type. Such scale precipitates in the upper part of the tubing (surface down to about 300 ft). Presence of scale restricted operations during pulling and running of the subsurface pump. In some cases it created stuck pumps and then a work over was needed.

Some deposits had low solubility but solutions of acids could often be used to remove such scales. The reasons for this problem have been analyzed and the conclusions are as follows: -

  1. Pressure drop at the wellhead (below 100 psi).
  2. High formation water production.
  3. High temperature (over 120 oF).

To prevent scale formation inside the well, it was found that increasing the wellhead pressure to 150 psi would significantly improve the situation. Ifscale existed, the removal was always done mechanically by a gauge cutter & home made wire brush. However, chemical treatment is under study as an economical and operational solution.

  1. Corrective Action:

As illustrated in the failure analysis, several modifications in the system design and equipment types were introduced in all the fields. Conventional geometry in addition to smaller size M-II pumping units have been used. The big change is in the rod design and the size & type of the down hole pump. Several things contributed to that change such as the discovery of new fields with new fluid properties and formation parameters. Table (3) shows the current surface and subsurface equipment.

Table-3: current surface and subsurface equipment

Item / Size / Type
D . H. P. / 30-250-RWAC- 24- 4
30-225-RHAC- 24- 4-2
30-200-RWAC- 24- 4
30-175-RWAC- 24- 4-2 / RWAC
RHAC
RWAC
RHAC
Rod string / (87) with 18 joints of 1” rod as sinker bars / High tensile strength
(140,000 to 150,000 Ib)
Grade “D”
Rod coup. / Standard size / Class T
Tubing / 3.5 “ * 9.3 Ib/ft
Surface unit / M - 912 D - 365 – 144
M - 640 D - 365 – 144
M - 465 D - 365 – 144
M - 320 D - 365 – 144
C - 912 D - 365 - 144 / Mark-II
Mark-II
Mark-II
Mark-II
Conventional
Prime mover / 75 HP
100 HP / Ultra high slip

As shown in table-3, four different sizes of subsurface pumps are currently used. This gives different scenarios to match with well production in order to maximize efficiencies. All the pumps are top hold-down and by running this style, the stuck pump problems were eliminated. Agiba has pioneered the modifications of the anchor to install at the top of the pump. This modification is tested and applied in more than 200 wells without any problems.